British Electricity International
Modern Power Station Practice
Third Edition incorporating Modern Power System Practice
ELECTRICAL SYSTEMS AND EQUIPMENT Volume D
Pergamon Press
MODERN POWER STATION PRACTICE Third Edition (in 12 volumes)
incorporating Modern Power System Practice
Main Editorial Panel D. J. Littler, BSc, PhD, ARCS, CPhys, FInstP, CEng, F1EE (Chairman) +Professor E. J. Davies, DSc, PhD, CEng, F1EE F. Kirkby, BSc, CEng, MIMechE, AMIEE H. E. Johnson P. B. Myerscough, CEng, I-IMechE, FINucE W. Wright, MSc, ARCST, CEng, FIEE, FIMechE, FInstE, FB1M
Volume Consulting Editor Professor E. J. Davies, DSc, PhD, CEng, FLEE
Volume Advisory Editor F. Beach, BSc(Eng), ACGI, DIC, CEng, F1EE, MIMechE
Authors Chapter
1 A. E. Clegg, CEng, FIEE E. C. Adams, DipEE, AMIEE R. A. Colley, DipEE, CEng, MIEE J. E. Durrant, BSc(Hons), CDipAF, CEng, MIEE T. Lepojevic, DipING(Belgrade), AM1EE J. E. Simpson, BSc(Hons), CEng, MIEE P. J. Simpson, CEng, MIEE
Chapter 2 J. N. Dodd, CEng, MIEE F. J. W. Preece, BSc, MSc, CEng, MIEE G. T. Williams, DipEE, CEng, MIEE Chapter 3
M. J. Heathcote, BEng, CEng, MIEE
Chapter 4 L. T. Smith, BSciFlons), CEng, MIEE Chapter 5 D. F. Oldfield, CEng, MIEE Chapter 6 P F. Partridge, BSc, CEng, M1EE F. Beach, BSc(Eng), ACGI, DIC, CEng, FIEE, MIMechE B. R. Hill, BSc, CEng, MIEE C. W. Poole, BSc(Hons), DipMS, CEng, MIEE D. L. Threlfall, BSc, CEng, MIEE Chapter 7 B. Barker, CEng, MIEE Chapter 8 E. C. FitzGerald, CEng, M1EE F. Ashurst, KEE Chapter 9 C. H. Spear, BSclEngi, CEng, F1EE Chapter 10 M. Ballinger, MIEEIE Chapter 11 J. t3. Hadwick, BEng, MIEE W. Morgan, BSc, CEng, MIEE Chapter 12 B. R. Hill, BSc, CEng, MIEE
Series Production Managing Editor
P. M. Reynolds
Production Editor
H. E. Johnson
Resources and Co-ordination
T. A. Dolling J. R. Jackson
MODERN POWER STATION PRACTICE Third Edition
Incorporating Modern Power System Practice
British Electricity International, London
Volume D
Electrical Systems and Equipment
PERGAMON PRESS OXFORD • NEW YORK • SEOUL . TOKYO
U.K.
Pergamon Press plc, Headington Hill Hall. Oxford 0X3 OBW, England
U.S.A.
Pergamon Press, Inc., 395, Saw Mill River Road, Elmsford, New York 10523, U.S.A.
KOREA
Pergamon Press Korea, KPO Box 315, Seoul 110•603, Korea
JAPAN
Pergamon Press Japan, Tsunashima Building Annex, 3-20-12 Yushima, Bunkyo-ku, Tokyo 113, Japan Copyright © 1992 British Electricity International Ltd
AN Rights Reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means: electronic, electrostatic, magnetic tape, mechanical, photocopying, recording or otherwise, without permission in writing from the copyright holder. First edition 1963 Second edition 1971 Third edition 1992 Library of Congress Cataloging in Publication Data Modern power station practice: incorporating modern power system practice/British Electricity International.— 3rd ed. p. cm. Includes index. 1. Electric power-plants. I. British Electricity International. TK1191,M49 1990 62.31'21 — dc20 90-43748
British Library Cataloguing in Publication Data British Electricity International Modern power station practice.-3rd. ed. 1. Electric power-plants. Design and construction I. Title II. Central Electricity Generating Board 621.3121. ISBN 0-08-040510-X 112 Volume Set) ISBN 0-08-440514-2 (Volume DI
Printed in the Republic of Singapore by Singapore National Printers Ltd
Contents Vi
COLOUR PLATES
Vii
FOREWORD PREFACE
iX
CONTENTS OF ALL VOLUMES
Xi
Chapter
1
Chapter 2
Electrical system design Electrical system analysis
I 84
Transformers
193
Chapter 4
Generator main connections
287
Chapter 5
Switchgear and controlgear
325
Chapter 6
Cabling
427
Chapter 7
Motors
623
Telecommunications
649
Emergency supply equipment
748
Chapter
Chapter
3
8
Chapter 9
Chapter 10 Mechanical plant electrical services Chapter 11
Protection
799 868
Chapter 12 Synchronising
948
INDEX
987
V
Colour Plates (between pp 496 and 497)
FIG, 3.11
Large core being built (GEC Alsthom)
FIG. 3.12 Completed core, showing frame bolts (GEC Alsthom) Eic,, 3.58 Core and windings of single-phase CEGB generator transformer (GEC Alsthom) FIG. 3.60 800 MVA generator transformer bank at Drax power station (GEC Alsthom) Pc. 3.64 Cast-resin transformers for installation in 415 V switchgear (GEC Alsthom) FIG. 5.1/
Two poles (of a three-phase group) of a forced-air cooled generator circuit-breaker installed at Dinorwig pumped-storage power station (British Brown-Boveri Ltd)
FIG. 5.12 One pole of a forced-air cooled generator circuit-breaker, with side covers and the connection to generator busbar removed (British Brown-Boveri Ltd) FiG. 5.13 Three-phase water cooled generator circuit-breaker showing connection into the generator phase-isolated busbar system (British Brown-Boveri Ltd) Fic, 5.14 Generator circuit-breaker control panel (British Brown-Boveri Ltd) FIG. 5.15 Cooling water plant (British Brown-Boveri Ltd) FIG. 5.18 Air plant control panel (British Brown-Boveri Ltd) FIG. 5.29 Typical 3.3 kV switchboard of Reyrolle manufacture FIG. 5.48 3.3 kV switchboard of Reyrolle manufacture. The three left hand units are 'fused equipment Class SI4A' and the three right hand units are 'air circuit-breakers Class SA'. FIG. 5.49 Typical 415 V switchboard of GEC manufacture FIG. 5.51 Typical 415 V switchboard of Electra-Mechanical Manufacturing Co manufacture Fic., 5.69 Switchboard formation of control gear featuring vacuum interrupters in association with protection for 3.3 kV service (GEC Industrial Controls Ltd)
HBC fuse
1-ro. 5.70 Example of control gear featuring vacuum interrupters in association with HBC fuse protection — for 3.3 kV service, showing the demonstration of the circuit earthing switch (GEC Industrial Controls Ltd)
vi
Foreword G. A. W. Blackman, CBE, FEng Chairman, Central Electricity Generating Board and Chairman, British Electricity International Ltd
FOR OVER THIRTY YEARS, since its formation in 1958, the Central Electricity Generating Board (CEGB) has been at the forefront of technological advances in the design, construction, operation, and maintenance of power plant and transmission systems. During this time capacity increased almost fivefold, involving the introduction of thermal and nuclear generating units of 500 MW and 660 MW, to supply one of the largest integrated power systems in the world. In fulfilling its statutory responsibility to ensure continuity of a safe and economic supply of electricity, the CEGB built up a powerful engineering and scientific capability, and accumulated a wealth of experience in the operation and maintenance of power plant and systems. With the privatisation of the CEGB this experience and capability is being carried forward by its four successor companies — National Power, PowerGen, Nuclear Electric and National Grid. At the heart of the CEGB's success has been an awareness of the need to sustain and improve the skills and knowledge of its engineering and technical staff. This was achieved through formal and on-job training, aided by a series of textbooks covering the theory and practice for the whole range of technology to be found on a modern power station. A second edition of the series, known as Modern Power Station Practice, was produced in the early 1970s, and it was sold throughout the world to provide electricity undertakings, engineers and students with an account of the CEGB's practices and hard-won experience. The edition had substantial worldwide sales and achieved recognition as the authoritative reference work on power generation. A completely revised and enlarged (third) edition has now been produced which updates the relevant information in the earlier edition together with a comprehensive account of the solutions to the many engineering and environmental challenges encountered, and which puts on record the achievements of the CEGB during its lifetime as one of the world's leading public electricity utilities. In producing this third edition, the opportunity has been taken to restructure the information in the original eight volumes to provide a more logical and detailed exposition of the technical content. The series has also been extended to include three new volumes on 'Station Commissioning', `EHV Transmission' and 'System Operation'. Each of the eleven subject volumes had an Advisory Editor for the technical validation of the many contributions by individual authors, all of whom are recognised as authorities in their particular field of technology. All subject volumes carry their own index and a twelfth volume provides a consolidated index for the series overall. Particular attention has been paid to the production of draft material, with text refined through a number of technical and language editorial stages and complemented by a large number of high quality illustrations. The result is a high standard of presentation designed to appeal to a wide international readership. It is with much pleasure therefore that I introduce this new series, which has been attributed to British Electricity International on behalf of the CEGB and its successor companies. I have been closely associated with its production and have no doubt that it will be invaluable to engineers worldwide who are engaged in the design, construction, commissioning, operation and maintenance of modern power stations and systems.
March 1990 vii
Preface Tne review of the original Modern Power Station Practice series carried out a few years ago revealed large gaps in its treatment of electro technology within power stations. Not unnaturally much of the content was also badly out of date. It was clear that a straightforward revision of the previous book would not suffice and that a totally new work was required. It was therefore with much enthusiasm that the team of authors of Volume D set out to write it since we all felt it was very timely to do so. The re-organisation of power station design and construction within the CEGB in 1971 created the Generation Development and Construction Division (GDCD). The Division set up an Electrical Branch which pulled together previously dispersed skills and experience in all aspects of power station electrical engineering covering power systems and plant as well as control, communications, data and instrumentation systems and equipment. Two of the volumes of MPSP, Volumes D and F, are largely based on the work done over many years by GDCD Electrical Branch. Volume D deals with the work of some 50 electrical design specialists in the power engineering field while Volume F covers a similar level of activity in the C and I field. One of the major tasks of the Electrical Branch has been to rationalise electrical system and plant design and development, and produce designs which meet operational needs in the most economic way and with the required level of reliability and performance. As the Head of the branch for many years I have felt privileged to edit Volume 1D. The twelve chapters describe in appropriate detail the design philosophies and techniques which have underlain the work of the Branch. They describe the solutions to the large number of design problems which have been identified and the plant which has been chosen and developed to equip electrical systems both within the different types of new power station which have been built as well as for replacement and modification tasks at existing stations. Since the formation of GDCD, CEGB projects have included most types of generating plant including AGR and PWR nuclear stations, fossil-fired stations (both oil and coal), gas turbine and diesel driven generators and a major hydro plant at Dinorwig. While most of the electrical equipment for these different sorts of power station is similar, the electrical system needs vary widely. The designs described in Volume D therefore deal with the requirements for all types of power station electrical plant and systems. Furthermore, while the rate of change of electrical power plant technology is not as fast as that in the light current area, there has nevertheless been considerable equipment development and an even greater change in design techniques and methodology. This is especially true in the analysis of electrical system design and performance and in some areas of plant development such as cable system design. Since the Electrical Branch has also been responsible for control, instrumentation, communication and data systems it has been possible to ensure co-ordinated complementary development of both heavy and light current systems. The many interfaces, e.g., cabling, power supplies, instrumentation, protection and metering have been engineered with a coherent systems approach. The light current technology in the control, instrumentation and data systems area is described in Volume F. The Advisory Editor for that volume, Mr M.W. Jervis, and I, as colleagues in Electrical Branch, have always striven to maintain a close co-operation on all aspects of electrical systems design. We hope that this integration of design effort will be apparent to the readers of Volumes D and F. I would like to record my most sincere thanks to my many colleagues who have produced Volume D and also Volume F. They have undertaken the work in parallel with their day to day responsibilities and have seen the task as an opportunity to put in writing a review of the results of their work for CEGB. I also wish to express my gratitude to Professor ix
Preface John Davies and Mr. Peter Reynolds for the great help and support which they have given me in the preparation of the volume. I believe that Volume D stands as a record of many years of high quality electrical design activity and that it will remain relevant as an exposition of the science for a long time. F. BEACH Advisory Editor — Volume D
Contents of All Volumes Volume A — Station Planning and Design Power station siting and site layout Station design and layout Civil engineering and building works Boilers and Ancillary Plant Volume B Furnace design, gas side characteristics and combustion equipment Boiler,unit — thermal and pressure parts design Ancillary plant and fittings Dust extraction, draught systems and flue gas desulphurisation Volume C
—
Turbines, Generators and Associated Plant
The steam turbine Turbine plant systems Feedwater heating systems Condensers, pumps and cooling water systems Hydraulic turbines The generator
Electrical Systems and Equipment Volume D Electrical system design Electrical system analysis Transformers Generator main connections Switchgear and controlgear Cabling Motors Telecommunications Emergency supply equipment Mechanical plant electrical services Protection Synchronising —
Volume E Chemistry and Metallurgy Chemistry Fuel and oil Corrosion: feed and boiler water Water treatment plant and cooling water systems Plant cleaning and inspection Metallurgy Introduction to metallurgy Materials behaviour Non-ferrous metals and alloys Non-metallic materials Materials selection —
xi
Contents of All Volumes Welding processes Non-destructive testing Defect analysis and life assessment Environmental effects Volume F Control and Instrumentation Introduction Automatic control Automation, protection and interlocks and manual controls Boiler and turbine instrumentation and actuators Electrical instruments and metering Central control rooms On-line computer systems Control and instrumentation system considerations —
Station Operation and Maintenance Volume G Introduction Power plant operation Performance and operation of generators The planning and management of work Power plant maintenance Safety Plant performance and performance monitoring —
Volume H Station Commissioning Introduction Principles of commissioning Common equipment and station plant commissioning Boiler pre-steam to set commissioning Turbine-generator/feedheating systems pre-steam to set commissioning Unit commissioning and post-commissioning activities —
Volume J Nuclear Power Generation Nuclear physics and basic technology Nuclear power station design Nuclear power station operation Nuclear safety —
Volume K EHV Transmission Transmission planning and development Transmission network design Overhead line design Cable design Switching station design and equipment Transformer and reactor design Reactive compensation plant I-1 VDC transmission plant design Insulation co-ordination and surge protection Interference Power system protection and automatic switching Telecommunications for power system management Transmission operation and maintenance —
xii
Contents of All Volumes Volume L — System Operation System operation in England and Wales Operational planning — demand and generation Operational planning — power system Operational procedures — philosophy, principles and outline contents Control in real time System control structure, facilities, supporting services and staffing Volume M — Index Complete contents of all volumes Cumulative index
Evan John Davies Emeritus Professor of Electrical and Electronic Engineering at Aston University in Birmingham, died on 14 April 1991. John was an engineer, an intellectual and a respected author in his own right. It was this rare combination of talents that he brought to Modern Power Station Practice as Consulting Editor of seven volumes and, in so doing, bequeathed a legacy from which practising and future engineers will continue to benefit for many years.
XV
CHAPTER 1
Electrical system design 1 Introduction 2 System needs Station operating criteria 2.1 2.2 Grid system operation criteria 2.3 Plant and personnel safety needs 2.4 Nuclear hazard needs 3 System descriptions 3.1 Main generator and station systems 3.1.1 Main generators 3.1.2 Generator transformers 3.2 Electrical auxiliaries systems 3.2.1 Auxiliaries system transformers 3.2.2 Interconnection 3.2.3 Essential systems 3,2.4 Emergency generation 3.3 Types of stations 3.3.1 Fossil-fired power stations 3.3.2 Magnox nuclear power stations 3.3.3 AGR nuclear power stations 3,3,4 P M nuclear power stations 3.3.5 Hydro and miscellaneous 4 System performance 4.1 Station and unit start-up 4.1.1 Plant required 4.1.2 Synchronising to the grid 4.1.3 Synchronising unit to station 4.2 Shutdown and power trip 4.2,1 Controlled shutdown 4.2.2 Power trip 4.3 The effects of loss of grid supplies 4.4 Station plant outages and faults 5 System choice 5.1 Operational requirements 5.2 Reliability of main and standby plant 5.3 Economics 5.4 Plant limitations 5.4.1 Switchgear current rating 5.4.2 Switchgear short-circuit rating 5.4.3 Large electric motors 5.4.4 System performance calculations 5.5 Maintenance and safety 5.5.1 Operational 5.5.2 Maintenance
Introduction The various electrical systems within a power station include those associated with the connection of the generating plant to the grid system and the very much larger number which are provided to distribute power supplies around the auxiliary plant within the station
5.5.3 Other safety interlocking 5.5.4 Nuclear safety 5.6 Quality assurance 5.6,1 Design quality 5.6.2 Product quality 6 Uninterruptable power supply MPS) systems 6.1 Introduction 6.2 Earlier UPS and GlS schemes 6.2.1 Motor-generator (MG) set schemes 6.2.2 Static inverter schemes 6.3 Development of UPS systems 6.3.1 Littlebrook D power station schemes 6.3.2 Drax power station schemes 6.3,3 Heysham 1 power station 6.4 System configuration and method of operation 6.5 System considerations and components 6.5.1 Voltage regulation 6.5,2 UPS system loads 6.5.3 Step-down transformers 6.5.4 Standby and spares philosophy 6.6 UPS equipment specification 6.7 UPS equipment performance requirements 7 DC systems 7.1 Introduction 7.2 DC system duties 7,3 DC system design 7.3.1 250 V DC systems 7.3.2 220 V DC systems 7.3.3 110 V DC systems 7.3.4 48 V DC systems 7.3.5 250 V. 220 V and 110 V DC circuit earthing 7.4 DC system analysis 7.5 Battery chargers and batteries 8 Electrical system monitoring and interlocking schemes 8.1 Introduction 8.2 Operational interlocking, monitoring and indications 8.3 Relay systems 8.3.1 Switchgear auxiliary contacts 8,3.2 Application of interlock schemes 8.4 Computer-based systems 8.5 Maintenance interlocking equipment 8.5.1 Key exchange boxes 8.5.2 Scheme application 8.6 Other safety interlocking
boundaries. The total electrical systems therefore interface with the whole of the power station installation. The systems can be summarised as follows: • Generator primary system and grid, typically 23.5 kV (660 MW) or 26 kV (900 MW) for units with grid voltages of 275 kV and 400 kV. 1
Chapter 1
Electrical system design • Station board system from grid, typically II kV derived from 132 kV, 275 kV or 400 kV. • Station and unit auxiliaries systems, typically at 11 kV, 3.3 kV and 415 V. • Einereency pow er supplies systems, typically gasturbine, diesel-driven generators connected at 11 kV, 3.3 kV, 415 V. • DC systems, typicall at 250 V, 220 V, 110 V, 48 V. • Uninterruptable power supply systems (UPS), typically at 415 V single and 3 phase, 110 V single-phase. The security required of the electrical supplies is determined by the importance of the power station plant ot equipment. For example, auxiliaries associated with the main unit which if lost would immediately cause loss of unit output, clearly require more secure supplies than services such as sump pumps used occasionally. The nature of the supplies also requires careful consideration by way of voltage and frequency limits, susceptibility to transients caused by faults or switching operations and the consequences of short breaks in supplies. As a matter of course, most items of plant and equipment are specified and tested for compliance with known standards. This will include their electrical performance. If the need for new types of equipment is identified then performance limits should be defined at the outset of any development work, where standards cannot be quoted. The degree of security must also be taken into account since parts of nuclear power stations will warrant a much higher level than, say, a small hydro station. It is necessary then, to recognise from the outset the importance of each item of plant when determining the nature and degree of security of electrical supplies it requires. The sources for auxiliaries supplies range from the grid-derived AC supplies, through to batterybacked AC and DC supplies and the 'short break' supplies. The bulk of the electrical auxiliaries load is normally arranged to be taken from the grid-derived AC supplies. This will mean that the outline design of the electrical auxiliaries system can benefit from previous know ledge and experience when considering alternative supply arrangements to a certain level at an early planning stage of a project. The alternatives will include, for example, unit and station transformer schemes, generator soltage switchgear schemes and FIV switch isolator schemes. Detailed descriptions of t hese and other schemes are given later in this chapter. The timely and accurate design of electrical systems is always easiest if at the outset, and at appropriate stages of the project, full details of electrical loading, rating and duty information can be established from the plant specialists, particularly for the major items, e.g., reactor, boiler, turbine-generator and operational ancillary plant. One way of achieving this is by in2
eluding standard electrical loading, rating and duty schedules in all the plant enquiry specifications, thereby committing tenderers to identify their design loads. It also assists in forming a comparison between competitive tenders and should be followed up with more accurate and detailed information at defined stages of the contract by the chosen contractors. By this means, the electrical system loadings can progressively be assembled and refined, enabling design ratings of transformers, switchgear, cables, etc., to be established for comparison of the various possible alternative electrical systems. The system designer would always present a recommended scheme by comparing the alternatives on a basis of first and lifetime costs and suitability for duty. Until this stage is reached, the electrical plant specialists cannot seriously begin to specify their requirements. It is possible, however, that the system designer has already taken account of the commercially available equipment, which will make the specifying of electrical components more straightforward. This chapter explains the approach and criteria used in determining the most suitable electrical systems for the various duties required at nuclear, fossil-fired and hydro power stations. There is a brief reference to other forms of generation, generally referred to as alternative sources of energy.
2 System needs 2.1 Station operating criteria In common with all other areas of design in power stations, the electrical system designers must have a clear definition of what operating criteria need to be achieved. In the case of the CEGB, station development particulars are formulated at the early planning stages which incorporate the Station Technical Particulars (STPs). The STPs contain the requirements for the main plant availability, operating flexibility and the control of units. In addition, they will include the technical requirements for the generator transformers, the plant auxiliaries supplies and the station protection arrangements. Various appendices will detail the specifications to be met and the finite limits to be achieved. From these, it will be apparent what minimum features need to be built into the electrical systems to achieve the station output while at the same time ensuring the safety of personnel and plant, a more onerous requirement on nuclear power stations. Further documentation is prepared for nuclear power stations to cover the safety aspects in the form of a Preliminary Safety Report. The interpretation of the STPs into electrical requirements becomes the designer's check list and generally will incorporate the following as typical: (a) Station rated output is required over a supply frequency range of 49.5-50.5 Hz, with pro-rata
System needs decrease in the range 49.5-47 Hz. Operation below 48.8 Hz will be very infrequent and for periods not longer than 15 minutes. (b) A fault, including a fire, in any section of any auxiliaries system shall not cause more than one main generator to trip under all normal operating conditions.
(e) The plant auxiliaries systems shall remain stable for three-phase faults of duration up to 200 ms on 'close-up' sections of the supergrid and grid busbars and the adjacent system, over a specified range of operating conditions. (d) The plant auxiliaries supply arrangements shall be designed to meet all the operating flexibility requirements, e.g., two-shifting, part-loading and load rejection. (e) The plant auxiliaries system shall satisfactorily withstand any internally generated switching or other transient overvoltages. (1) The plant auxiliaries system shall accommodate the generator operating with a terminal voltage in the range of 95% to 105% of the rated value. In addition to the needs that the auxiliaries electrical system must meet as requirements of the STPs, the designer may incorporate system features to improve availability by supplementing those required by the STPs. For example, the incorporation of alternative supplies to selected switchboards could reduce outage ti me and consequently lost revenue from a main generator following an electrical fault; such a design feature will be subjected by the designer to economic justification. This and other 'additional requirements' will be explained in more detail in Section 4 of this chapter.
2.2 Grid system operation criteria While the power station has specified operating criteria, the grid system into which it generates also has such criteria defined for it. The significant ones are those associated with frequency, voltage and total or partial loss of the grid connections in the vicinity of the power station. The frequency ranges have been outlined in Section 2.1 of this chapter. In addition however, looking from the grid into the power station, it must be remembered that below 47 Hz the auxiliaries system may be protected by an automatic trip, although an excursion of this sort has a very low probability. There are also the onerous transient frequency excursions as a result of full-load rejection and possibly periods of steady high frequency up to 52 Hz, which the auxiliaries system will be expected to withstand without tripping for periods not exceeding 15 minutes. To put the likelihood of local frequency excursions
in perspective, outside the range of 50.5 Hz, it is generally expected at the following estimated rates: • Greater than 50.5 Hz, I incident per year. • Greater than 52 Hz, 0.2 incidents per year. In addition to the frequency ranges above, the auxiliaries system will be required to accommodate the network voltage variations. The 400 kV supergrid system voltage will normally remain within the range 400 kV +5%. The maximum voltage which can arise is 440 kV, but this condition would not be permitted to last longer than 15 minutes. The 132 kV system voltage can vary between the limits of 132 kV ± 10 070. Internally generated switching or other transient overvoltages on the auxiliaries system were mentioned above, but added to these will be any transferred surges from the grid system. The amplitude of step changes of voltage on the 400 kV system are not expected to exceed +6%. The effects of total or partial loss of the grid connections to power stations vary depending on the type of station, the most significant effects being on nuclear power stations. It is essential to re-establish AC supplies within known timescales in these instances to maintain nuclear safety. This is described more fully in Section 2.4 of this chapter. In the case of conventional power stations, the safety of plant and personnel is normally taken care of by the DC systems if AC supplies are lost. Re-establishing the AC supplies does not usually require the same emphasis other than for returning the main generators to service.
2.3 Plant and personnel safety needs It will be appreciated that maximising the output from power stations must be achieved within recognised standards, codes of practice and rules to ensure the safety of the power station plant and personnel. In electrical system design terms, adequate safeguards must be incorporated to meet the statutory requirements of the Electricity Regulations and the Health and Safety at Work Act, relating these to safety rules. The CEGB Safety Rules set out the mandatory requirements for establishing the safety of persons at work. The electrical systems must build-in means of achieving operational and maintenance regimes to comply with all necessary safety requirements. Operationally, the major considerations are to ensure that the normal and abnormal duties and prospective fault capabilities for circuits and system configurations are not exceeded. The circuits must be rated for required voltage and for normal and fault currents calculated during the design, and in the case of the switchgear must be capable of making and breaking current during normal and fault operations. Interlocking or monitoring schemes need to be incorporated to ensure that ratings are not exceeded due to operator 3
Chapter 1
Electrical system design error. Descriptions of such schemes are contained later in this chapter. For maintenance of plant and equipment there is a CEGB mandatory requirement to isolate and earth all circuits at voltage levels of 3.3 kV and above before work can commence. At 415 V and below, proof of isolation must be established. Details of these features are described later in this chapter. Protection of the plant must be arranged to prevent damage without resulting in an increased loss of availability. For example, should a turbine-generator trip as a result of loss of AC supplies or trip and cause loss of AC supplies, the lubricating oil systems are maintained by means of DC motor-driven pumps. Other means of maintaining the safety of plant will be described later in this chapter when considering what safeguards need to be incorporated into the system.
2.4 Nuclear hazard needs The electrical systems provided at nuclear power stations must relate to the plant and equipment required to prevent the release ultimately of radioactivity to the atmosphere. Initially the favoured source of electrical supplies to these safety systems would be derived from the grid network. This network has finite li mits of its own, the voltage and frequency limits having been described in Section 2.2 of this chapter. However, when these limits are exceeded they can, particularly in the case of nuclear power stations, be regarded as being the equivalent to a total loss of grid supplies. The likelihood of this 'total loss' must be considered in relation to the time factors associated with maintaining nuclear safety. For example, in the case of the Sizewell B pressurised water reactor (PWR) station ti me bands of 0 to 2 hours, 2 to 12 hours and greater than 12 hours have been considered. The probability can be related to the required stage by stage availability of the plant needed to meet the safety case. Consideration of the needs of the safety related plant to the probabilities of losing grid supplies invariably leads to the provision of a supplementary AC source of supply by means of on-site generation. In most cases this has been provided by either gasturbine or diesel-driven generators. The choice between the two will depend on several factors including the rating and availability of the auxiliary generation required. For example, the CEGB have utilised gasturbine generators of 17.5 MW rating on earlier AGR nuclear power stations. For the later Heysham 2 AGR power station, diesel generators up to 8 MW rating have been installed. A significant factor regarding the Heysham 2 diesel generators was the need for a fast start-up/loading requirement. This influenced the generator parameters, e.g., a low subtransient reactance value was chosen to achieve fast start-up while still containing the prospective fault contribution to an acceptable level. The manner in 4
which each has been utilised is described later in Section 3 of this chapter.
3 System descriptions The generating units of each power station deliver their electrical output to the National Grid via connections at 400 kV or 275 kV, although at some older generating stations the generators are connected to the grid at 132 kV. As part of the design of new power stations, dependent on the network and capacity requirements of the transmission system in the area, consideration may be given to building a new 400 kV substation at locations where existing generating plant is connected at lower voltages, i.e., 275 kV or 132 kV. The present policy is to use SF6 insulated metalciad 400 kV switchgear, often mounted indoors, particularly on coastal or polluted sites. If extensions to existing substations is the economic method of connecting new generators, then 'open' busbar design would be employed using SF6 circuit-breakers. The stations require supplies to be available at all ti mes for supplying 'station' auxiliaries and depending on the system design, for providing a supply to the 'unit' auxiliaries for starting up and shutting down of the units as shown in Fig 1.1. In the cases where generators are connected to the grid via a generator voltage switch, the units are normally started and shutdown via the generator/unit transformer route, though a separate source for 'station' supplies would still be provided for the station auxiliaries and for standby to the unit transformer as illustrated in Fig 1.2. If available, this would normally be derived from a 132 kV source since, for the rating of 500 MVA and below, the transformers are well proven, economic and the switchgear is cheaper. If however, 132 kV is not available on the site, to create a 132 kV substation might require long cable routes or overhead lines and possibly provide additional intergrid reinforcement. This may be more costly than considering station transformers connected at 400 kV.
3.1 Main generator and station systems 3.1.1 Main generators Generators of 660 MW (776 MVA) rating having a nominal output voltage of 23.5 kV. The output of the machine to the generator transformer is via phase isolated connections, naturally air cooled and rated at 20 000 A, either directly connected or switched by purpose built generator voltage switchgear, depending on the auxiliaries system design. Details of the generator main connections and generator voltage switchgear are given in Chapters 4 and 5 respectively. At present these are the largest generating sets installed in the UK. Designs are being developed for generators rated at 900 MW, in which case the gen-
System descriptions m••■•
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, CIRCUIT SPEAKE. N'7_,'
".Na_._Y OPEN
3kv UNIT AUXILIARY BOARD CIRCUI BREAKEP CLOSED 3 3kv UNIT DRIVES
UNIT SERVICES TRANSFORMERS 3 3 415v
415v
UNIT SERVICES BOARD
Fro. 1.1 Typical unit station system for a 660 MW generator
erator terminal voltage will probably increase to 26 kV. The present style of main generator connection arrangements will be capable of carrying the increased output current, although forced cooling by either air or water may be required. The limiting factor for naturally cooled connections would be accommodation of the greatly increased size, particularly within the generator terminal centres. This is fully described in Chapter 4. 3.1.2 Generator transformers
Each generator is connected to the grid system via a generator transformer with the appropriate voltage ratio. The CEGB fit on-load tap changers to accommodate the grid voltage variations and the voltage operating range of the generator. It has established a 'registered design' of generator transformer for the 660 MW generating units rated at 800 MVA and made
up of 3 single-phase units. The intention of the registered design is to achieve a high level of reliability by avoiding all but essential change to proven systems in detail design, materials or components (see Chapter 3). The 800 MVA rating is based on taking the main generator 776 MVA rating plus the possible 44 MVA output from a gas-turbine generator, contributing from the 11 kV level via a unit transformer, less a minimum unit auxiliaries load of 20 MVA. For the generating units being considered at 900 MW (nominal) rating, a generator transformer rated at 1145 MVA, also in 3 single-phase tanks, is being developed, taking into account an overload capability from the main unit. As with the 800 MVA rating, on-load tapchangers will be fitted for the same reasons. There have been instances on nuclear power stations using generator voltage switchgear, where the on-load tapchanger has been arranged with an auto5
Chapter 1
Electrical system design
GRID
GRID
GENERATOR TRANSFORMER
GENERATOR VOLTAGE SWITCH
STATION TRANSFORMER UNIT TRANSFORMER INTERCONNECTOR
ti kV UNIT BOARD
11kV STATION BOARD
UNIT AUXILIARIES
CIRCUIT BREAKER CLOSED
STATION AUXILIARIES
(1: 1) CIRCUIT BREAKER NORMALLY OPEN
FIG. 1.2 Typical generator voltage switch system for a 660 MW generator
matic feature. This has been done to deal with the problem that arises when a generator trip results in the opening of' the generator voltage switch but retains the grid connection. Under these circumstances, the 11 kV switchboard voltage could fall to a level such that the direct on line starting of a boiler feed pump may not be achieved. The auto-tap facility raises the voltage in a timescale and to a level capable of achieving a pump start thus securing an initial boiler feed without relying on the emergency feed pumps. Should this scheme not achieve boiler throughput, the emergency pumps connected to the 3.3 kV system will still ensure reactor safety.
3.2 Electrical auxiliaries systems These systems provide the power for the station auxiliaries and are nowadays almost always designed on the unitised principle. In the past, in some cases, particularly early magnox and AGR stations, this principle was not strictly followed, the former consortia •ho built the stations having used criteria different from present day practice. The general arrangements for electrical auxiliaries systems are described below, and in their design due comisance is taken of the limits and constraints imposed by the equipment commercially available which is or could be type approved for the particular application. In the unit principle, all auxiliaries associated with 6
starting and running the unit at CMR output are connected to the unit electrical system. This must be designed such that one fault including a fire, does not lose the output of more than one generating unit. Similarly, plant which does not have an immediate effect on the running of the unit, will be connected to the station electrical system. It is required that a fault on this plant will not immediately propagate into the unit electrical system and affect unit output. To achieve this, the electrical and mechanical plant, switchgear and cabling is segregated between the units, and between the two halves of the station system, (normally known as 'station A' and 'station B'). Segregation is not normally provided between the unit and station systems. Standard voltage levels of 11 kV, 3.3 kV and 415 V have been selected to accommodate the very wide range of plant drives and equipment. In the case of the 11 kV unit system, a major constraint is the thermal current rating of the largest circuit-breaker commercially available and approved for use on CEGB systems. The present nominal rating is 3150 A which, when calculated in relation to the transformer standard BS171 requirements, relates to an incoming transformer rating of approximately 60 MVA. Therefore, if the unit load is in excess of this, two unit transformers are required. The fault interrupting capability of the switchgear also adds a constraint, which is discussed under 'system choice' in Section 5 of this chapter.
System descriptions Supplies to the unit board are derived from a unit transformer on the basis of one per switchboard, the primary of which is teed-off the generator voltage main connections system. All auxiliaries requiring electrical motor drives, whose combined operation is necessary to keep the unit venerating, are connected to the unit system. Large motors rated at 1500 kW and above are generally connected to the 11 kV system, e.g., electrical boiler feed pump , circulating water pumps, gas circulators at nuclear power stations and boiler fans at fossil-fired power staticns. In the case of nuclear power stations, particularly early AGRs (and some magnox), the 11 kV unit systems form part of the nuclear safety case. This is because the 11 kV provides a preferred source of supply to the essential system, and in some cases feeds essential plant directly, e.g., gas circulators. In this context, essential plant is that which is required following a reactor trip to shut down the reactor safely and remove post-trip decay heat. Back-up emergency generating facilities are provided at the appropriate voltage level should the grid connection fail. If the emergency drive is greater than 1500 kW and therefore requires connecting to the II kV system, emergency generation at II kV is provided. This is described in more detail later in this section. The 11 kV unit switchboard as well as supplying large motors also provides a feed to the 3.3 kV unit system via 11/3.3 kV oil-filled unit auxiliaries transformers located outdoors. For nuclear stations there is, in addition, an 'essential system' which normally derives supplies from 11/3.3 kV 'essential transformers'. If grid derived supplies are not available, the essential system is supplied by on-site generation (gas turbines or diesels). The thermal current limits applicable to unit transformer incoming circuit-breakers apply equally to the auxiliaries and essential transformers, which are limited by the largest approved circuit-breaker at 3.3 kV, rated at 2400 A, giving the largest practical size of transformer rating of around 14.5 MVA. Unit related auxiliaries in the range 150-1500 kW are connected at 3.3 kV, although motors outside this range may be connected for special cases. The 3.3 kV system also provides feeds to the 415 V unit system via 3.3/0.415 kV unit services transformers. These transformers are normally naturally air cooled ' AN' type and mounted in the switchboards. The 415 V system is distributed around the power station, with switchboards located in switchrooms as close to the load as possible. Motors up to approximately 150 kW are connected to this system although motors above this rating may be considered in special cases. To maintain a high availability of electrical supplies to auxiliaries, duplicate feeds are supplied to each switchboard. This may be achieved by two incoming supplies and a bus section switch, or by one incoming supply and a cabled interconnector to another switchboard which has its own incoming supply. For both these
methods, each transformer feeding the switchboards must be rated to include the standby requirement of the other transformer. Those auxiliaries which are common to two or more units or are not necessary to maintain unit output, are connected to a 'station' electrical system, i.e., not specifically associated with any one unit. The 11 kV station system has several duties, and the rating chosen will reflect the duty it is called on to perform. It does however share the same constraints as the 11 kV unit system brought about by the circuitbreaker ratings. The station system may be required to provide a source of supply to large 11 kV 'unit' drives, directly in some system arrangements or in a standby mode in others to cater for a unit transformer outage. The station transformer rating must be chosen accordingly. The different duties expected of station transformers are outlined in Section 3.2.1 of this chapter. Feeds from the 11 kV station system are provided to a station 3.3 kV system via 11/3.3 kV station auxiliary transformers. Common station services, such as coal handling plant at fossil-fired power stations, would be supplied at this voltage level. The rating of motors at 3.3 kV would be on the same basis as the unit system. Station supplies at 415 V are derived from the 3.3 kV switchboards via 3.3/0.415 kV services transformers, usually of the 'AN' type, mounted in the switchboards and located in switchroorns as near to the load centre as layout permits. On some nuclear power stations while the station system is not required ultimately in the safe shutdown case, in many cases it may provide grid derived supplies to nuclear plant and relieve the demands on the essential system. For example, at Heysham 1 AGR, the 132 kV grid derived supplies can be made available from the station system to the main gas circulator motors via converters following a reactor trip. As such it would be required to be engineered with this duty in mind.
3.2.1 Auxiliaries system transformers
Unit transformers As mentioned above, the supply to the II kV unit board is via a dedicated 23.5 kV/11 kV unit transformer, with a rating chosen to match the unit load, but limited to 60 MVA due to the largest approved rating of 11 kV circuit-breaker. Another consideration the designer must take into account is the choice of transformer impedance. A unit transformer has a typical impedance of approximately 15% on rating. When this value is used in the analysis of the station's electrical auxiliaries system, it may require alteration. For example, the electrical system regulation may be too high, making the starting of large 11 kV squirrel-cage induction motors direct-on-line (DOL) difficult. The maximum rating suitable for DOL starting at 11 kV 7
Chapter 1
Electrical system design is about 11 MW. Also, unacceptable voltage conditions may be experienced at the lower voltage levels. In this case the impedance may need to be reduced. In con11-1 with this, too low an impedance may give rise to unacceptable fault levels on the 11 kV system, especially when unit and station supplies are paralleled during station start-up and shutdown procedures. The subject of parallel operation is discussed more fully Section 4 of this chapter. Solutions to this conflict are seldom easy and almost always cause complications and additional expenditure. The options are: • Use assisted starting techniques, i.e., 'soft' starting, for the largest motors by utilising static or rotary converters. This may also be combined with woundrotor motors, rather than squirrel-cage. a
Use automatic fast transfer systems when switching between unit and station supplies to reduce the transfer time to one or two cycles. This permits break before make without allowing the speed of running motors to drop below recovery times. If make before break is ever regarded as an acceptable option, it would limit the time during which prospective fault levels exceed ratings.
• Use generator voltage switchgear to provide start-up supplies via the generator and unit transformer. • Use HV connected unit transformers, with HV disconnection of the generator/generator transformer combination. • Increase the system voltage to say 15 kV thereby increasing the possible transformer rating. This is not being pursued in present designs, mainly because it would mean either creating a 15 kV system with a separate unit transformer for the very large drives only or raising the voltage for all the motors catered for at II kV, e.g., induced and forced draught fans, CW pumps. These problems have become more pronounced with he proposed introduction of larger generating sets, c.g., 900 MW, without steam-turbine-driven boiler feed pumps and relying on large full duty electric feed pumps in a 3 x 50c% configuration each rated at 13.5 MW. It should be noted that past practice has beLn to design systems whereby unit and station systems arc capable of being paralleled for start-up/shutdown and 'or standby duty without exceeding fault levels (sce Section 4 of this chapter).
The station transformers' duties may be summarised as follows: • Supply the total 'station' load (due to outage of the other station transformer) as well as supplying the starting load of a unit. • Supply its proportion of the station load and the CMR unit load when acting as replacement for a unit transformer. It should be noted that to accommodate the single fault criteria (that one fault should not lose all station supplies), a minimum of two station transformers will be required for the station. The above duties become more complex when more than two station transformers are used on multi-unit stations. However, the above principles remain the same. Similar to the principles outlined in the section on unit transformers, the impedance of the station transformer must be chosen to enable paralleling with the unit transformer, for start-up and shutdown and to allow the largest electric motor (normally the feed pump) to be started. As mentioned above, the use of higher rated sets may preclude paralleling and alternative methods may be required to achieve successful methods of changeover for start-up and shutdown supplies. It should be noted that the above criteria are a general guide, and each proposed electrical system is designed with the particular requirements of the station addressed specifically. More information is given in the following sections.
3.2.2 Interconnection To enable flexibility of operation and to cater for planned or forced outages, interconnection between different switchboards at the same voltage levels is normally provided. These are usually cabled interconnections with circuit-breakers at each end. The associated circuit-breakers are arranged such that one is normally closed. This energises the cable permanently, so that any cable fault is detected and cleared by the protection immediately, rather than when the circuit is energised just prior to being required. Interconnection may be one of two distinct types: • Where the two supplies may be paralleled, thereby giving continuity of supply.
Slur on transformers
• Where an alternative supply is required but the two sources may not be paralleled due to a paralleled fault level in excess of the switchgear certified rating.
The supply for the 11 kV station boards is via a 132 kV, 275 kV or 400 kV/11 kV station transformer, the rating of which is chosen to provide a starting facilit ■, for the unit, and standby capacity to the unit transformer in the case of its being unavailable, due to an outage.
Where interconnection is provided between supplies which may be paralleled (as there is no fault level restriction) but may be out of phase and frequency, check synchronising facilities will be provided at the normally open circuit-breaker. Where interconnection
8
System descriptions would produce unacceptable fault levels at the switchboard, an indication or interlocking system is provided to ensure that the circuit-breaker is not closed. Indication and interlocking systems are discussed further
• To provide an independent supply to the auxiliaries of the main steam units in the event of unacceptably low frequency on the Grid system.
3.2.3 Essential systems
• Use as output plant capacity to meet system requirements. In this mode of operation the gas turbines will normally be used for 'Peak generation' purposes, and will also act as 'hot standby'.
All power tations require essential systems, but a fundamental difference exists between fossil and nu-
• Ability to start-up a station without external Grid supply.
in Section 8 of this chapter.
clear plant. Fossil plant only requires essential electrical systems to maintain unit output and to protect plant from damage following a loss of supply. The consideration of these systems only needs to examine economic and personnel safety issues, and the systems are designed to achieve these objectives. Nuclear plant requirements are much more onerous, due to the fission product decay heat which requires removal to avoid an unacceptable risk of a radiological hazard and expensive plant damage. Essential systems for all the power stations are based on additional on-site prime movers, either diesel generators or gas-turbines, together with batteries and chargers providing no-break supplies. Present designs also use uninterruptable power supplies (UPS) to provide instrumentation and power supply requirements which are battery-backed. These systems are also used in normal operation since they provide a stable voltage and frequency supply 'isolated' from the transients experienced by the main auxiliaries system. They are based on centralised schemes of static or rotary inverters, with a battery backing for a timescale in the region of 30 minutes to cater for loss of the battery charger or its AC supplies. For more details on UPS see Section 6 of this chapter. The DC system voltage levels are chosen for selected duties such as emergency drives and emergency lighting at 250 V, switchgear with the higher current closing solenoids at 220 V, protection, direct control and switchgear tripping at 110 V and telecommunications, remote control and indications at 48 V. The batteries are usually of the lead-acid Plante type. The DC systems are described later in Section 7 of this chapter, and the batteries and chargers in Chapter 9. 3.2.4 Emergency generation As mentioned previously, on-site generation is provided for emergency supplies to the auxiliaries system on all power stations. There are many differing types, dependent on the type of station and the needs which have to be met. Generators may be powered by gas turbines, or diesels and may be at voltages of 11 kV or 3.3 kV. On-site generation for large fossil-fired stations since the early 1960s has been provided by gas turbines at 11 kV, and has satisfied the following needs:
• To provide an independent supply in order to ensure the operation of essential drives, such as the main bearing lubricating oil, in the event of loss of normal supplies. This duty is, in effect, a back-up to the DC battery system. On-site generation for nuclear power stations assumes a more important role as it becomes part of the nuclear safety case. All plant required to safely shut down and cool the reactor is normally supplied from an essential system, which derives its preferred supply from the grid supply. Failure of the off-site connection requires the on-site generation to connect, usually automatically, to the essential system. The large quantities of decay heat in the reactor core/boiler system cause prolonged requirements for feedwater, steam dumping and reactor core cooling after the turbine-generator has been tripped.
3.3 Types of stations The CEGB have a wide variety of power stations from base load coal-fired and nuclear power stations to oil-fired, hydro, pumped-storage and gas turbine types, and gas-fired and wind power pilot installations. The bulk of the demand is of course met by the base load stations which this section will concentrate on. The present design policy to take the CEGB into the t wenty-first century is to have both large coal-fired stations and nuclear stations of the PWR design. Combined cycle gas-turbine (CCGT) installations are also a future possibility. The coal-fired stations will be at the 2 x 900 MW size and the first PWR will be at Sizewell B with a single reactor and 2 x 660 MW turbine-generator units. With the increasing concern for controlling the emissions from coal-fired stations, retrofitting of Flue Gas Desulphurisation (FGD) plant is taking place at selected existing coal-fired stations and included at the design stage for the new 2 x 900 MW designs. The additional loading imposed by FGD on the auxiliaries system is very significant, resulting in the designers assessing different schemes for meeting the various methods of providing FGD plant. FGD is an international problem being tackled in various ways, but initially the CEGB are employing the limestone/ gypsum method. The additional auxiliaries system load9
Electrical system design it-1g for this process at a 2 x 900 MW station is of the order of 45 MW for the entire plant. Considering now the auxiliaries systems for the various types of stations, this section describes the different aspects associated with each.
3.3.1 Fossil-fired power stations The majority of existing CEGB fossil-fired plant is fuelled by coal or residual oil with a small number capable of being fired by either. There are a few gas turbine stations with units of about 70 MW using distillate fuel, and Hams Hall C power station which is dual-fired, using coal or natural gas. The latter example using natural gas was a pilot conversion scheme to assess its feasibility. Basically for a given location and station output, the electrical auxiliaries system for a coal-fired or oil-fired station would differ only in respect of the loads associated with the fuel handling and combustion plant. For a coal-fired station, this plant consists of the unitised draught plant (induced draught, forced draught and primary air fans), coal mills and feeders and the precipitators together with the common services associated with coal handling, dust handling and ash disposal systems. For a 2000 MW coal-fired station of 4 x 500 MW units, operating at CMR, the auxiliaries load is typically 31 MVA per unit plus a station load of 20 MVA. The comparative figures for a similar sized oil-fired station are 20 MVA and 13 MVA respectively since the unit load will not have the PA fans, precipitators and coal mills and the station loads will not have the coal, ash and dust handling systems. The fuel oil system does not make the same load demands as the coal fuel systems. Take as an example, the electrical auxiliaries system provided for the 2000 MW (3 x 660 MW) Littlebrook D oil-fired station. The outline of the auxiliaries system is shown in Figs 1.3 and 1.4. An important consideration in the adoption of the most economic station supplies arrangement was the availability of an existing 132 kV substation on the site. One of the SIP requirements was for the output from the three gas turbines, for system reasons, to be available to the grid independent of the operation of the main units. Each gas turbine generator rating is 35 MW, which required three station transformers, since one transformer circuit (maximum rating 60 MVA) could not accommodate more than one gas turbine generator for thermal reasons nor could the auxiliaries system for prospective fault level reasons. The use of three station transformers however does lend itself to a simpler and more flexible system configuration than is possible with the more general two station transformers scheme. At the 11 kV level, the station/ station interconnections maximise the availability of the station transformers across all three units and their gas turbines. These interconnections are an example of how an auxiliaries system design can economically 10
Chapter 1 justify providing facilities beyond what could be provided to meet only the STP requirements. Each 3.3 kV unit auxiliaries board is supplied by duplicate 8 MVA transformer feeders, each capable of supplying the 3.3 kV auxiliaries load and thereby providing standby to each other. The transformer i mpedance was chosen to enable both transformers to be in service at the same time. There was no need therefore to provide any unit/station interconnection at the 3.3 kV level. At the 415 V level, a sectionalised unit services/ station services switchboard was introduced, each section fed from its respective 3.3 kV auxiliaries board. This provides a better utilisation of transformer capacity at this level than having separate unit and station 415 V boards with duplicate supplies for each from the respective 3.3 kV unit or station auxiliaries system; thus reducing the cost, space and maintenance requirements. Transfer of loads from one transformer to its standby is carried out off-load since the prospective fault level at 415 V does not permit carrying this out on-load. For the fossil-fired stations, slightly different auxiliaries systems have evolved as the CEGB moved from the 500 MW unit period to the 660 MW units of the late 1960s. All systems used the unit/station principle. Most of the stations with 500 MW units had four units each with two station transformers, typically shown in Fig 1.5.
Drax power station was designed as a 6 x 660 MW unit station, with three units initially installed, followed in the early 1980s with the three remaining units. The station auxiliaries system catered for the six units from the outset by providing four station transformers. Despite the long time interval between the construction of the first and second halves of the station, there was great emphasis placed on replication wherever possible for the completion phase to ensure the operational and maintenance convenience of the station as a whole. The outline of the auxiliaries system for the six-unit station (to 11 kV level) is shown in Fig 1.6. The auxiliaries systems for the present 900 MW unit coal-fired station designs are being assessed as for past stations against their STP requirements and economics. The alternative systems considered include using generator voltage switchgear, which the CEGB first used at Hartlepool and Heysham AGR stations, but which to date has not been used at fossil-fired stations. All generator voltage switchgear used by the CEGB on their modern large units has been the 3 x singlephase airblast type, designed and manufactured by Brown Boveri. A description of the design, construction and performance of the types used by the CEGB is given in Chapter 5. It has not been a requirement at fossil-fired stations to make grid supplies available via the generator transformer, and generator voltage switchgear has not been economically justifiable compared with a unit/ station transformer scheme.
System descriptions
4c30kV
415V
CIRCUIT BREAKER CLOSED
C4RCUIT BREAKER NORMALLY OPEN
FLO.
1.3 Littlebrook D electrical system
The introduction of FGD plant follows the CEGB policy decision to reduce the overall sulphur emission from its power stations. To achieve this, it is proposed in the first instance to retrofit FGD equipment to existing coal-fired stations starting with Drax. In addition, the CEGB will be providing FGD equipment on all their new coal-fired stations. For a 2000 MW station burning 2% sulphur content coal, the load consumption of the FGD plant using the limestone/ gypsum process is of the order of 53 MVA. When compared with a nominal station load of 51 MVA, this represents 104% additional auxiliary power required, which constitutes a significant increase in capital and through-life costs for the station. The electrical auxiliaries system currently proposed for a 2 x 900 MW subcritical coal-fired station design, which includes the FGD plant, is shown in Figs 1.7 and 1.8. It will
be seen that the FGD plant electrical supplies have been derived from the unit/station electrical systems. All voltage levels of 11 kV, 3.3 kV and 415 V are required to accommodate the loads, including large booster fans fed at II kV. Cabling system design is made more complex with this arrangement since the unit/station system is determined by the layout of the generator, station and unit transformers and major switchboards. These are located at the opposite end of the station to the FGD auxiliaries and plant. Alternatively, the FGD plant can be considered as a separate entity, giving rise to the provision of a dedicated FGD electrical auxiliaries system centred on a location adjacent to the FGD plant and with its own Grid connections. The comparison between the two approaches is mainly one of economics. For new 11
Electrical system design
Chapter 1
70
,
so
7 4:
rata, ia 0 yd .,. .0 a.
"
3
4..7 .111aC.0
1
11 0/..0:
•aal )a
77.■ 71711, 1 1174
Fic. 1.4 Littlebrook D electrical auxiliaries system
projects the most economic approach utilises the unit/ station electrical system, although the separate electrical system has clear benefits for retrofit FGD schemes.
eyed differently for each station and differently from those which would be adopted today. However the fundamentals for reactor safety remain the same. They are:
3.3.2 Magnox nuclear power stations
• To ensure a main coolant flow over the reactor internals, so cooling the reactor core and fuel.
The CEGB has eight magnox reactor nuclear power stations. These stations were commissioned over a period spanning eleven years, from Bradwell in 1962, to Wylfa in 1973. The stations were built by different consortia as 'turnkey' contracts, and hence have many differences in terms of output and design. The design measures which ensure reactor safety, which is the most onerous requirement on system design, are achi12
• To ensure a flow of feedwater to extract the heat developed in the reactor, and hence provide steam to power the main turbine-generators. • To provide reactor auxiliaries and services, e.g., pressure vessel cooling water flow. • To provide controls and indications for the above.
System descriptions
■■•■
•••.1
•
0•.1 :10
C 2,
So,
1 4V•
1
00
'
244OC
1 2=i! ! E
L' !
15. ss. Wre STATION ai.i•
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7
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-
-
-
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,
VI [Wit". 5 an III
-
O
3.3 1.1- ApOn
4;
1■ 61.1 •0.0 2
0 SD ARE FITTED WITH 3 3kV MOTOR SWITCHING DEVICES
FIG. 1.4
(cont'd) Littlebrook D electrical auxiliaries system
These requirements apply to a reactor whether it is operational, or in the initial period of shutdown, when fission product decay heating occurs, during the posttrip cooling period. AdeCluate post-trip cooling must be available for all credible faults and accidents that can be sustained by the reactor, and sufficient redundancy and diversity of mechanical plant and systems ensures this. Clearly, electrical equipment, where required as the power source for the mechanical plant and systems, must also be capable of meeting the redundancy and diversity requirements. Having satisfied the demands of reactor safety, the electrical system must also enable the station to be
operated at full or part output with the best possible efficiency and operational flexibility. To achieve all of the above objectives, the electrical system is structured into two parts: (a) The main electrical system. (b) The essential electrical system. The main electrical systems of all magnox stations are based on the unit and station system principle. This has already been described in Section 3 of this chapter. In the case of the rnagnox stations however, different voltage levels (e.g., 6.6 kV) and sometimes discrete systems for a particular purpose (e.g., gas circulator 13
Electrical system design
Chapter 1
400kV
8
30 25MW GAS TURBINE
MVA ,
2 5',
AS LNG No
IkV 500M VA 30MVA
3 0 0 TO UNIT No 2
2 1( 10 MVA 8%
5 0 1.105
3 30/
SCM VA
01:10000 0 CI . ,_...,.._./ ,..____,_____, z IL 2-z< 1 `2 1 Lz. 1.0 E 8L, c0
o LL:L m
DEAERATOR PUMP B
,
0}
4150
Z
CO
415V
IL IL
LU
0
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ri p
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(7, 0
ta cr a
co
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3 MAIN AIR HEATER
ON MILLS
MAIN AIR HEATER
R'LE
ON MILLS
415V
AIR PUMP a
0' 50
AIR HEATER OIL PUMP
1.1.1
IL IL
E D
E
AIR HEATER DRIVE
LJ
FIG. 1.5 Typical electrical system for 4 x 500 MW coal-fired units
supplies) are used. Although the details of the design are different in each case, the objectives are the same, viz safe and economic operation of the power station as a whole. The essential electrical system is an integral part of t he main electrical system, but is designed so that it 14
can operate independently of it. The safety of the reactor is dependent on the essential electrical system as all items of plant necessary for post-trip cooling are connected to this system, e.g., emergency boiler feed pumps, pony motors for gas circulators, necessary auxiliaries, etc.
System descriptions
8 88I
I B 2B 0 ci; ILSo) I
I
iect
TO No 3 UNIT
3 3kV
STANDBY SUPPLIES
4l5V
STANDBY SUPPLIES
TO No 4 UNIT
TO No 2 UNIT
3.3kv STATION SERVICES BOARDS COAL & ASH PLANT GENERAL SERVICES
rtj CIRCUIT BREAKER CLOSE°
CIRCUIT BREAKER NORMALLY OPEN
Flu. 1.5 (coed) Typical electrical system for 4 x 500 MW coal-fired units
The main electrical system provides the preferred supply to the essential electrical system, via unit or station auxiliary transformers. If there is a loss of grid causing loss of supplies to the essential electrical system, then on-site generation will provide supplies to the essential system only. Usually, gas turbine or
diesel generators are used for this purpose. There are certain items of plant which can tolerate a short interruption of supplies, and these will be connected to AC switchboards supplied by the on-site generation. The short break in supplies due to the starting period of the on-site generation is acceptable 15
Chapter 1
Electrical system design •■■••••■•■■■■
GENERATORI '32
•••••
■•■
IGSNERATOR 2
•
3E1,EPAC—L.P
NIT TRAT.S,': 2 5 % 1 E.-
UN'T BOARD 5
UNIT
UNAT
BOARD
O BOARD
4
STATION TRANSEORMEP 'A
3
UNFI BOARD 2
UNIT
BOARD
,
STATION TRANSFORMER 2A 4OF,el .r
25
0
CW PUMP
CV/ PUMP 8
0
38 0 29 EMERGENCY BOWES FEED PUMP
EmERGENCY BOILER FEET FLAPS
500TOLOWER COMPRESSORS AA
0
CIRC,u7 BREAKEq CLOSED
•13
0
CIRCUIT BREAKER T.ORMAL,
SOOT8LOWER COMPRESSORS
FIG. 1.6 Drax power station electrical system to 11 kV level
from reactor safety considerations. Plant items which cannot tolerate any break in supplies (e.g., instrumentation, controls and indications) are connected to supplies derived from a DC system, i.e., batterybacked. Normally the DC supplies are provided from the essential system AC switchboards via rectifier units, the battery being maintained in a fully charged state. Following a loss of supplies to the essential system, the battery maintains supplies to the plant items connected to the no-break system during the short period of time while the on-site generation is starting up. When the on-site generation is fully available, the DC supplies are again provided from this source, and the battery is recharged to a fully charged state. The main and essential electrical systems thus provide supplies for both reactor and plant safety, and economic operation of the station when supplying power to the National Grid. 3.3.3 AGR nuclear power stations
The choice and ratings for the auxiliaries systems for the AGR stations are similar to the fossil-fired stations 16
and provide supplies in the same way on a unit and station basis. Although the electrical auxiliaries system is a single integrated design, it has two major constituent parts namely the main electrical system and the essential electrical system. The most recent of the CEGB AGR stations is at Heysham 2 and its design has followed CEGB design philosophies evolved over the period since the first AGRs were designed. Heysham 2 as described represents the latest design aspects of the AGRs. The main electrical system function is primarily to operate the station in producing its output, while the essential system is to ensure that the CEGB meets the required safety criteria in supplying safety related reactor auxiliaries plant both following a reactor trip and in the general longer term. Heysham 2 (2 x 660 MW) is the largest auxiliaries power system for a two-unit station installed by the CEGB. Considering first the main electrical system, the auxiliaries power system for the two units, numbered 7 and 8, are illustrated in Figs 1.9 and 1.10. Unlike Heysham I, the grid connections have been made to both the 400 kV and 132 kV grid substations.
System descriptions
400kV 409 275 132AV
GENERATOR TRANSFORmER
STAT'ON TRANSFORMERS 20 60NIvA
GE"LERATGR TRANS ,DPMEk 1" '1 9,1VA
GENERATOR 909MW
60
69 MVA
60
MvA
MVA
UNIT TRANSFORMERS
STATION 0 BOARD IA
UNIT BOARD 1A
$
ir
STATION BOARD'S
UNIT BOARD'S
OSTATION BOARD 2A
116V D
O
CI STATION BOARD 2B
25
2
UNIT TRANSFORMERS
0 UNIT BOARD 24
D
6
UNIT 804100 25
CIRCUIT BREAKER CLOSED CIRCUIT BREAKER NORMALLY OPEN FIG. 1.7 Electrical system for 2 x 900 MW coal-fired units
This enabled the setting up of an electrical system which matched the reactor quadrant concept and provided higher integrity grid connections. Each reactor/ generator has four 11 kV switchboards; A, B, C and D. Station boards A and B deriving supplies from the 132 kV system and unit boards C and D from the 400 kV system. In this way, there is an 11 kV switchboard associated with each reactor quadrant and it is at this level that the four-trained electrical system starts and is continued to the lower voltages. The auxiliaries associated with each quadrant all derive supplies down through the various voltage levels from the same 11 kV source. The lower voltage levels are 3.3 kV and 415 V. The drives connected at each voltage level are: • 415 V up to and including 150 kW. • 3.3 kV up to and including 1500 kW. • 11 kV above 1500 kW. The gas circulators (5220 kW), CW pumps (1700 kW) and emergency boiler feed pumps (10 500 kW) are therefore supplied at 11 kV. At the 3.3 kV level, two systems are established, the X system for cooling the reactor by forced circu-
lation and the Y system to feed water into the main boilers, after a trip. The 415 V system continues with X and Y systems. In addition, at 3.3 kV there are auxiliaries associated with the turbine-generator for which the electrical needs are similar to most 660 MW units, and a unit auxiliary and station auxiliary system has been created by deriving supplies from the appropriate 11 kV level (D and B). This follows through to the 415 V level and in addition provides supplies for the reactor services auxiliaries. Each generator output at 23.5 kV passes to the grid via a generator switch and a generator transformer to 400 kV. The generator also feeds its auxiliaries via t wo unit transformers (23.5/11 kV). Each unit transformer normally supplies one II kV board but it is rated (60 MVA) to be capable of supplying the normal loads of two 11 kV boards, via the 11 kV interconnectors. It can be seen that each unit board is interconnected to a station board, i.e., D to A and C to B. This makes possible either a 400 kV or 132 kV derived source. Likewise the two station transformer secondaries are each rated to supply the normal load of a unit/station board. The two station transformers are also interconnected at 11 kV. Again each secondary winding is rated 17
Chapter 1
Electrical system design
400kV
ild5MVA GENERATOR TRANSFORMER
•
GENERATOR I 900MW 60M VA
60M VA
1 , kV UNIT BOARD IA
Ikv UNIT BOARD 10
El 0
El SCE
8
8 12 5MVA
3 3kV AUXILIARY
O OTRD A
41) ELECTRIC FEED PUMPS
12 5MVA
(I
?
8
12 5MvA
12 5MVA
POD 3 3kV AUXILIARY — BOARD B
3 3kV UNIT AuXIL1ARY BOARD B
3310 UNIT AUXILIARY BOARD A
O
Do
8
0 8
8
8
4 , 5V FOC, SERVICES BOARD A
415V PRECIPITATOR BOARD A
i
tt,
8
a 5V FGD SERVICES BOARD B
415v MILL SERVICES BOARD 8
415v FAN 4156 FAN SERVICES BOARD A SERVICES BOARD
415V MILL SERVICES BOARD A
415V PRECIPITATOR BOARD B
0 415V TURBINE BOARD A
415 BOILER BOARD A
475V BOILER BOARD B
415V TURBINE 0 BOARD a
FIG. 1.8 Electrical auxiliaries system for 2 x 900 MW units including FOD plant supplies
to supply the normal loading of two I I kV station boards. Two conditions need to be considered here; • A station transformer can only act as standby to the other station transformer if its own reactor is shutdown. • A station transformer can only act as standby to one unit transformer at any one time on the basis that generating with more than one normal 11 kV source unavailable is not permitted. This leads to the three-winding station transformer having two secondary windings rated at 60 MVA, whereas the primary is rated at only 90 MVA. The essential electrical system is an integral part of the main system and is centred on the 3.3 kV level. The diesel generators are the ultimate back-up for the provision of electrical supplies. They are connected at 3.3 kV since the critical safety auxiliaries are at this level and below. 18
The decision to have a total of eight diesel generators for the two reactors was taken on cost grounds. The initial proposal had been for sixteen, which allowed one to be associated with each X and Y system but could not be economically justified. The restriction to eight diesel generators caused connection design problems both for operation and for cabling as each is connected and rated to supply the post-trip needs of corresponding X or Y systems of both reactors. This fixed the X diesel generator rating at 5.2 MW and the Y diesel generator rating at 6.735 MW. Y is the larger rating because the emergency feed pumps are much larger than any X system drive. The X system diesel generators, as well as supplying 3.3 kV and below, supply the main gas circulators via converters with variable frequency output, 1 Hz to 50 Hz, up to a voltage of 3000 V. The diesel generator supplies are regarded as short break supplies, i.e., loading of them cannot take place for approximately 26 s. There is however, a need for
System descriptions
32 , 275 , 400kV
120160.60FAVA
415v GENERAL SERVICES BOARD BOARDS
I SCE
STATIC CONVERTER EQUIPMENT
CIRCUIT BREAKER CLOSED
CIRCUIT BREAKER NORMALLY OPEN
FIG. 1.8 (coned) Electrical auxiliaries system for 2 x 900 MW units including FGD plant supplies
supplies to some loads which do not suffer a break, i.e., an uninterruptable power supply system (UPS). The UPS supplies at Heysham 2 are derived from battery-backed static inverters. The X system has a large UPS load requirement, including 3-phase drives. To maintain the 'trained' design concept, each X and each Y system has an appropriately rated UPS system; at 100 kVA, 3-phase 415 V output for each X system and 6.3 kVA single-phase 110 V output for each Y system., Additionally, each unit has unit and station UPS systems of 200 kVA, single-phase 415 V output for other than essential loads, e.g., unit guaranteed instruments and unit computer. As at all other stations, DC systems are provided both for normal usage and also for those situations when DC is absolutely essential, such as switchgear operation. For this reason all X and Y systems have discrete closing (220 V) and opening (110 V) batteries. In fact, the closing batteries are solely dedicated to that duty.
The unit and station DC system design needs to have in addition, a 250 V DC system for emergency lighting and turbine-generator emergency drives. 3.3.4 PWR nuclear power stations The CEGB has embarked on a series of nuclear power
stations of the PWR type and have based the station design on the American SNUPPS system. The lead station is at Sizewell B in Suffolk, where there is an existing magnox station. The electrical auxiliaries system, however, accommodates a UK design evolved around a twin-generator/single-reactor system, whereas the SNUPPS design has a single generator. The electrical system chosen provided a grid connection at 400 kV for each generator and a similar 400 kV grid connection for each of the two station transformers. Although the grid connections are to a common substation, each connection can be electrically segregated from the other by means of isolators and circuit19
HE YSHAM 13751/ AND 4001/V SUBSTATION
1327LV
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electrical system for Unit 7 and common services
ys.Am 132wV AND TIOOK V SUBSTATION
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4111711,V
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fisEr 4 rpsvcrs.EL cy8 , -
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6
do 415V ESS V SER ED 800 ,
415V ESS BD ecy,
I:113 CIRCUIT BREAKER CLOSED
II: 111 CIRCUIT BREAKER NORMALLY OPEN
1.10 Heysham 2 — electrical system for Unit 8 showing essential and common services interconnections
1A1 N ks VFLE 8 NIT 23 SO Tk V UN I T THAWS TRANSF 7 uON IESE L IE . 5÷ t u..W ,,, 11.1.14kV 1E L ir 3 3kV GEON (SO SINGH I I
I
_
_
1 ,,i ESS SINGR
6
T E1/9 .. 1., 1.. : Ei 7C, n , i, B Eki ,),(14N R ETA 1r ,D ,. .E 1,,,N 3s2 A, 1 REACTOR
TR ANSF 7 L, /1E1 RIESE I. GE NE RA TORS
.
v
3ASTATION MANSE 8
3 3kV DIESEL
GENERATORS ESSENTIAL SWITCHGE AR
suoOposep waisAs
415V DIESEL 75ER BD. AY8
6 SER 80 RCXV
y
415V AUX BLR
1
.415V ESS. o $ER. BD. 88X
4I5V ESS.
• sPA. ED. BUY
W T.P SERV BD
A
.r
415V ESS SER. 813. BAY
415V REAC
1.1
310JCHLOHINAItON
415V DIESEL SERVICES BOARDS
A
6
41SV ESS y SER. ED. flAX y T e H' 415V DIESEL &SFR I1T1 AXE
164,5:007..,1
4155/ESSENTIAL SERVICES BOARDS
Electrical system design breakers. This is important since any fault on the grid system or on one of the units should not jeopardise the single reactor operation or affect the output of the healthy unit. The electrical system is illustrated in Figs 1.11, 1.12 and 1.13. The 11 kV system is arranged into four 11 kV sections, each fed by one of the four off-site (grid) connections. Each unit and station pair of 11 kV sections is normally run paralleled through an inductor (to limit the fault current), so that the loss of one connection does not cause a total loss of 11 kV for that unit. The generator is connected to the generator transformer via a generator voltage switch, across which the generator is automatically synchronised. The loss of any of the reactor coolant pumps causes a reactor trip which is a prime reason for running the unit and station boards in parallel. Each of the four 11 kV switchboard sections provides a supply to one of the four functionally independent essential electrical 'trains', and is the normal and preferred source of supply. Each 'train' includes a 3.3 kV switchboard normally supplied from an 11 kV switchboard section via a 11/3.3 kV essential transformer. A diesel generator is connected to each 'train' 3.3 kV s witchboard, and is started and connected to it in the event of failure of the preferred electrical supply from 11 kV. All the plant required to remove post-trip decay heat is connected to the essential system at 3.3 kV and 415 V. It is considered a credible fault sequence that all four diesels may fail to start on demand following a complete loss of AC power from the Grid. The defence against this occurrence must ensure that the PWR is maintained in a safe condition, post-trip, by producing the following: • Feedwater to the steam generators via the auxiliary feed system. • A supply of water to the reactor coolant pump (RCP) seal to maintain the integrity of the primary circuit. The manner in which this is achieved is described in Section 4 of this chapter. 3.3.5 Hydro and miscellaneous Hydro stations are not common in the CEGB, although the Scottish Boards have a number of smaller stations. The advantage of the hydro station is that a very fast response in station output is achieved to meet sudden load demands on the grid network, e.g., due to the loss of a generating set elsewhere. The output of a traditional hydro station is determined by the replacement of the stored water in the top reservoir by natural means. Its value is therefore finite and dependent on how readily the stored water can be replenished. The electrical system for this type of station is relatively straightforward and met by providing a small station supplies system and appropriate 22
Chapter 1 grid connection for transmitting the station output. However, the most recent hydro station designed and built by the CEGB is a pumped storage scheme at Dinorwig. This is an 1800 MW station consisting of 6 x 300 MW generator-motor sets. All six sets are capable of generating full output using water stored in a high level lake which is discharged into a lower lake at about station level. The machines can also act as motors running in the opposite rotational direction to pump water from the bottom lake back into the top reservoir at a time when the grid system is lightly loaded. The electrical system design principles at Dinar wig took account of the following specific design aspects. The station is sited at a location where no grid substation existed previously and therefore a new 400 kV substation was required for connection of the generator-motor sets. Each generator-motor has its own three-phase, 340 MVA transformer. The 1-1V windings of these transformers are connected in pairs to the 400 kV switchhouse. This consists of two section circuit-breakers between the three generator-motor transformer circuits, and two line circuit-breakers for the two 400 kV connections to the Pentir substation some 11 km distant from the power station. For environmental reasons these connections use 400 kV oil-filled cable. The outline of the station electrical system is illustrated in Fig 1.14. To run the sets up as pumps, starting supplies are derived from either of two dedicated starting transformers and associated variable frequency sets, with a common starting busbar. The starting transformers derive their supplies from the 400 kV grid via two of the generator-motor transformers. The busbar is sectionalised however so that any faults can be isolated. Each of the two startup equipments is rated to start-up one machine at a ti me. There is also an alternative means of starting-up a set as a pump by back-to-back connection to another machine running as a generator. Machine excitation is derived from an excitation transformer. The excitation supply must be available prior to starting the machine in the pumping mode, whether using the starting equipment or the backto-back alternative it should not be subject to phase reversal. Each machine therefore has its own excitation transformer connected to the HV side of the generator-motor transformer. In the absence of grid supplies, a machine can be run-up as a generator by deriving excitation from the 240 V station DC system until it becomes self-excited via the excitation transformer. Each generator-motor is connected to its transformer via an air-blast circuit-breaker and reversing isolators incorporated into the 18 kV busbar connections system. The circuit-breaker is necessary to allow disconnection of the machine for phase reversal or shutdown, while still keeping the generator-motor transformer in service to maintain the electrical supplies to the station.
System descriptions
r 1 32 KV
1
1 32KV
EHV GRID CONNECTIONS
")
(
1
400KV
3
cs
400KV
1
1
(
GENERATOR TRANSFORMER 32
GENERATOR TRANSFORMER 31
GENERATOR 32
GENERATOR
31
UNIT TRANSFORMER 31
UNIT TRANSFORMER 32 STATION TRANSFORMER 31
11KV
(
ji3
(
2) 2 ) )))) L_LD__J PEEiDs Cw
3 3XV
415V OTHER AREAS
L
.
TURBINE AUXILIARIES
TURBINE HOUSE DIESEL GENERATORS
ESSENTIAL ELECTRICAL SYSTEM
()
1
\ 3 3K V)
3XV
BATTERY CHARGERS AND LOW VOLTAGE SYSTEMS
FIG. 1.11
PWR electrical system showing inter-relationship with off-site systems
Earthing of the generator system is achieved in the normal manner using generator neutral earthing modules. To cater for the period when the generator circuit-breaker is open, system earthing, i.e., on the generator transformer side of the disconnector, is achieved by earthing the unit transformer HV winding rather than using a dedicated earthing transformer or a system earthing module connected to the 18 kV System.
The number and rating of the unit auxiliaries led to the adoption of 415 V as the unit system voltage. On the station system however, because of some larger motors (up to about 850 kW), a station system voltage level of 3.3 kV was chosen. The system design incorporates three station transformers, each rated at 10 MVA and teed off the 18 kV main connections to three of the six machines. In this way, station transformer capacity is available such that 23
Chapter 1
Electrical system design
400Av
5 " JR! TRANSFORMER
23 5.4001,V GENERATOR 7pANsFoRmER
STATION TRANSFORMER I
,
NEDTRAL EARTH RESISTOR B
1 I kV STATION BOARD)
/1 0 STATION Aux TRANS 1
L-
0
r1 3 3KV UNIT AUX BOARD 1
6 iL
S EC T A
Y
UNIT ALIT TRANS 1 B
MAINFEED PUMP ?C
MAIN FEED PUMP
NEUTRAL EARTH ‘-,-' REACTOR RESISTOR IA COOLANT PUMPS
MAIN CW PUMP
UNIT AUX TRANS A
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BOARD
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y
9
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1>
4p5v cw PUmPHOUSE HYPOCHLORITE PLNT LOAD CENTRE I
FIG. 1.12 PWR unit/station electrical auxiliaries system
the total station services requirements can be met, even with a 3.3 kV tailworks feeder outage, using only two transformers and leaving the third transformer to act as a standby. Each is therefore rated to meet the simultaneous duties of supplying half the cavern 3.3 kV and 415 V station services, the headworks and tailworks services and, when the normal Area Board supply is unavailable, the 400 kV 24
cable cooling plant. To meet the requirements of the STPs, diesel generators are provided in order that the station can be started in the generating mode in the absence of grid supplies. In addition, the diesel generators maintain essential services in the cavern such as lighting, heating and ventilation plant to the personnel areas, battery chargers and normal drainage.
System descriptions
4204V
STATION TRANSFORMER 2
GENERATOR TRANSFORMER 2 400kV
- 23 5ioe EARTHING MODULE 24
235 • •
T
RANSP cdP
NEUTRAL EARTH RESISTOR 2A
MAIN GENERATOR 2
INDUCTOR 2
T . 4E RA EAR'. RES 1SfOR 25
¶IkVUNITBOAF102
Ilk's( STATION BOARD 2
STATION AuX TRANS 2
UNIT (1 Aux TRANS 28 VT CUE
0.
NEUTRAL EARTH RESISTOR 2C EL'
Lii 04 ILL Ll
z
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LOAD CENTRE 3
CW HOUSE HYPOCHLORITE PLNT TRANS. 2
0
y 415vcvo PUmPHOUSE HYPOCHLORITE PLNT LOAD CENTRE 2
Flo. 1,12 (cont'd) PWR unit/station electrical auxiliaries system
The electrical system design has to recognise the
function of the pumped-storage scheme to provide very rapid response to extra load demand. The start-up supplies are arranged such that a fault on any machine being started will not affect a unit which is operating in a generating or pumping mode by the provision of section isolators. This also enables starting busbar maintenance to be carried out with minimum affect on
machine availability. Considering the miscellaneous forms of power generation, the CEGB has considered several renewable energy sources. Of these sources, the most cost effective being pursued is wind turbine-generators (WTGs). These are mostly located in very remote locations and as such are generally unmanned. The CEGB has tried several sites, including the Orkneys, Carmarthen Bay 25
Electrical system design
Chapter 1
FROM ilkV STATION BOARD 1
FROM likV STATION BOARD 2
ESSENTIAL DIESEL GENERATOR
ESSENTIAL DIESEL GENERATOR 4
ESSENTIAL TRANSFORMER 4
NEUTRAL EARTHING
NEUTRAL EARTHiNG RESISTOR NER
RESISTOR NER
0
0
j
1 Ti
y),,„v,„ENT BOARD , j\
NEUTRAL EARTHING RESISTOR NE R
0
j:f
yA„,,,, ESSENTIAL
i
i r1 $$1666$1
<
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op <72 LLp ,JJ CE CC
415V ESS DIESEL LOAD CENTRE
,y
415V ESS DIESEL LOAD CENTRE
1/ 6 RUHSLOADCENTRE1
RUHS LOAD CENTRE 4
415V ESS DIESEL MCC 1
415V ESS. DIESEL MCC 4 ( ,
(
PRESS HTRS LOAD CENTRE 4
y
e
415V
415V ESSENTIAL LOAD CENTRE 4
6
ESSENTIAL MCC lE
415V ESSENTIAL MCC 4E
415V ESSENTIAL MCC 1C
415V ESSENTIAL MCC I A
d 5V ESSENTIAL MDC 1B
6
e
e
415V ESSENTIAL MCC 4C
415V ESSENTIAL MCC 4A
415V ESSENTIAL MCC 4B
FIG. 1.13 PWR essential electrical AC systems
26
4y
System descriptions
FROM 11EV UNIT BOARD
FROM I IkV UNIT BOARD 2 ESSENTIAL DIESEL GENERATOR 3
ESSENTIAL DIESEL GENERATOR 2
EsSENTiAL TRANSFORMER 2 NEUTRAL SART H INC RESISTOR
NER
NER
0
CD
I
3„VE
„
ENTIAL
„
ARD
ESSENTIAL TRANSFORMER 3
NEUTRAL EARTHING RESISTOR
2
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I
T
NEUTRAL EARTHING RESISTOR NER
3. ESSENTIAL BOARD
1
LU Li_
NEUTRAL EARTHING RESISTOR NER
E!I
500 500
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cc
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< 0
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RuH$ LOAD CENTRE 3
e
1 E 55 5E Rv TRANS
1 ESS
SERV. TRANS 3
415V ESS DIESEL MCC 2
2
U
415V ESSENTIAL LOAD CENTRE 2
I
(
415V ESSENTIAL iOAD CENTRE 3
6
e
19 415V ESSENTIAL MCC 2F
(4415v ESSENTIAL MCC 3F
415V ESSENTIAL MCC 2E
415V ESSENTIAL mCC 2C
(415v ESSENTIAL MCC 2A
,
r
PRESS. IITRS. LOAD CENTRE 3
PRESS HTRS LOAD CENTRE 2
6
415V ESS. DIESEL MCC 3
415v ESSENTIAL MCC 28
(415V
e
ESSENTIAL MCC 3E
(45V ESSENTIAL MCC 3C
415V ESSENTIAL MCC 3A
415V ESSENTIAL MCC 38
NOTES MOTOR RATINGS (SHOWN IN SHAFT kWI ARE INDICATIVE ONLY
FIG. 1.13
(coned) PWR essential electrical AC systems
27
Electrical system design
Chapter 1
NG EQUiPMENT 1
STARTING EQUIPMENT 2
400,18k V GENERATOR-MOTOR TRANSFORMER 1
18kVn 1kV STARTING TRANSFORMER 1 18kV/3 3kV STATION TRANSFORMER 1
18kV/41SV UNIT SERVICES TRANSFORMER 1
A A
1 M3PP
18kW717V GENERATOR-MOTOR EXCITATION TRANSFORMER 1
1 M3G
•
11.07
1 M2
2M3PP
18kV GENERATOR-MOTOR 1 CIRCUIT BREAKER 2M7 I MO 18kV GENERATOR-MOTOR 1 STARTING ISOLATORS 18kV GENERATOR MOTOR 1 1 A3 BRAKING SWITCH GENERATOR. MOTOR 1 EARTHING SWITCH
1M GENERATOR. OO
18kV GENERATOR MOTOR 2 CIRCUIT BREAKER
1 S4
2M0
GENERATOR-MOTOR 2 STARTING ISOLATORS 18kV GENERATORMOTOR 2 2A3 BRAKING SWITCH 18kV GENERATORMOTOR 2 EARTHING SWITCH
2M1 2S4
NV STARTING BUSBAR SECTION ISOLATORS Y3 18kV STARTING EQUIPMENT 1 OUTPUT ISOLATOR
18kV STARTING BUSBAR SECTION ISOLATORS STARTING EQUIPMENT OUTPUT TRANSFORMER 1 BY-PASS ISOLATOR
Fic. 1.14 Dinorwig electrical system 28
System performance and Richborough. In all these sites, the wind turbines have had ratings of between 1 and 3 MW. Present thinking is to develop 'wind parks', each wind park will have about 15-20 machines feeding into the Area Board system at 33 kV and 66 kV. The 'needs' for an electrical system for such generators are very much less onerous than for a conventional power station, especially as they are intended to be unn nned. The machines will be self-starting and will syl,:hronise themselves onto the Area Board network automatically. A simple switching system is envisaged, with tee-off connections to supply 'unit' services, if required. Battery capacity will be installed in a limited form to provide essential lighting, heating and any control supplies which may be required. The main WTG is mounted on top of a cylindrical steel pole which, at the bottom, houses the switchgear, etc. Power is transmitted to the wind park distribution network from the machine via a 'twisting' cable, necessary as the rotor and machine assembly follows the wind around.
4 System performance
4.1 Station and unit start-up For all types of power stations, start-up can only be achieved if there is sufficient electrical power available from either a grid connection or a large on-site power source such as a gas-turbine generator. Grid connections will be either 132 kV, 275 kV or 400 kV depending on the availability at the site. 132 kV would be preferred, due to the cost savings in switchgear cables and transformers. However this decision, made at the planning stage, must take into account factors such as: • Is 132 kV available at the proposed site? • Will the 132 kV system need to be reinforced to supply the power station requirements? • If present, is it intended to be kept for the life of the new station (due for example to Area Board bulk supply requirements)? • Is the 132 kV in the correct geographical location on the proposed site to avoid long and complicated cable runs? • Are there sufficient spare circuit-breakers or bays available or the capacity for extension to feed the station requirements? Another consideration is the phase angle difference between the 132 kV system and the 400 kV system, since the unit system will be connected to 400 kV via the generator transformer and there may be some electrical distance between the two voltage levels. In some cases this can be quite excessive and may well be outside
the range of the approved check synchronising equipment (see Chapter 12). In addition, large phase angle
differences cause large circulating currents when the unit and station systems are paralleled. This will be reflected in a short time requirement for a high rating of the unit transformer which may well lead to unacceptable constraints. Phase angle differences of about 10 ° are considered acceptable. Whichever primary voltage levels are chosen, startup power is usually supplied to the power station via station transformers. However, where, generators are connected to the system via generator voltage switchgear, start-up power may also be provided via the generator transformer/unit transformer route. Although stations have been built with generator voltage switchgear and no station transformers, it is not a practice which would be recommended today. This is because a complete loss of supplies to half the station could occur following the tripping of a generator [-I V circuit-breaker as a result of a major fault in the zone protected by the overall unit protection (see Chapter 11 on Protection), causing immediate and longer term operational restrictions. If a station requires start-up power when external grid supplies are not available, i.e., black start, it will be necessary to provide power sources at the II kV voltage level by means of on-site generation of sufficient capacity diesels or gas-turbines, or off-site generation, e.g., gas-turbines at another adjacent generating station with local interconnection. It - should be noted that GTs may have other duties such as 'peak lopping' or 'frequency support' or emergency generation. This is discussed more fully in Section 6.1 of this chapter. For start-up conditions, the station electrical system is interconnected to the unit electrical system usually at 11 kV to provide power from the station transformer to the unit system. The generator transformer HV circuit-breaker and unit transformer LV circuitbreakers are open at this time. This arrangement is shown in Fig 1.15. The method of achieving this differs from station to station, but the principle is the same. Most fossilfired stations have unit boards interconnected by cable, but nuclear stations have a variety of arrangements. Early magnox and AGRs differed widely in the method of achieving start-up supplies, but AGRs such as Hartlepool and Heysham / and 2 introduced a generator voltage switch, allowing the generator/unit transformer combination to provide starting power (see Fig 1.10). An electrical auxiliaries system arrangement for start-up with a generator voltage switch is shown on Fig 1.16. 4.1.1 Plant required
All power stations require at least one CW pump and one 50 07a electric boiler feed pump available and
running to start up a unit. In addition, fossil plant 29
Chapter 1
Electrical system design
GRID
GRID'
GENERATOR TRANSFORMER
UNIT TRANSFORMER
STATION TRANSFORMER
11kV STATION BOARD
11 kV UNIT BOARD
STATION AUXILIARIES
UNIT AUXILIARIES
1
3 CIRCUIT BREAKER CLOSED
FIG.
# CIRCUIT BREAKER NORMALLY OPEN
1.15 Arrangement for station start-up (direct connected generator)
GRID
GRID
GENERATOR TRANSFORMER GENERATOR VOLTAGE SWITCH
UNIT TRANSFORMER INTERCONNECTOR
STATION TRANSFORMER
likV STATION BOARD
1 1 kV UNIT BOARD
UNIT AUXILIARIES
(13 CIRCUIT BREAKER CLOSED
STATION AUXILIARIES
Iti t) CIRCUIT BREAKER NORMALLY OPEN
FIG. 1.16 Arrangement for station start-up (generator connected by a generator voltage switch)
requires either coal mills or oil pumps and draught plant, e.g., FD and ID fans, PA fans, etc. Gas-cooled nuclear plant requires gas circulators running on main motors or pony motors at approximately 15% speed, whereas water reactors require reactor coolant pumps. Both nuclear types require various supporting aux30
iliaries to be available during the run-up stages, the poor quality steam being dumped until the correct quality is achieved. When steam of correct quality is being produced, the turbine-generator will be run up to speed with all the unit supporting auxiliaries being powered from
System performance
the station transformers via the unit/station interconnectors. 4.1.2 Synchronising to the grid
When the turbine-generator is run up to the correct speed, it is synchronised to the grid via the generator transform r HV circuit-breaker (see Fig 1, 17) if the generator is directly connected to the generator transforme , or at the generator voltage switch if one is provided (see Fig 1.18). This is normally achieved using dedicated automatic synchronising equipment,
control of which is located in the main control room. However, the turbine automatic run-up equipment could well contain an automatic synchroniser and in this case the synchronising equipment mentioned above would no longer be required. Manual check synchronising may be achieved using portable check synchronising trolleys in the main control room. 4.1.3 Synchronising unit to station
When the generator is synchronised to the grid and lightly loaded, it is appropriate to transfer the unit
GRID (TYPICALLY 400kV)
GRID (TYPICALLY 132kV)
11kV STATION BOARD
UNIT BOARD
MANUAL CHECK SYNCHRONISING VIA SYNCHRONISING TROLLEYS AUTO SYNCHRONISING VIA DEDICATED EQUIPMENT
FIG. 1.17 Synchronising points for a direct connected generator
GRID (TYPICALLY 132kV)
Fs]
F_
Fi 71
MANUAL CHECK SYNCHRONISING VIA SYNCHRONISING TROLLEYS
AS AUTO SYNCHRONISING VIA DEDICATED EQUIPMENT
FIG. 1.18 Synchronising points for a generator connected via a generator voltage switch 31
Electrical system design loads to the unit transformer. This is achieved by paralleling the unit and station boards for a short time via the 11 kV interconnector. Check synchronising facilities, by means of control room located synchronising trolleys, will be necessary, as the two sources may be out of phase and frequency. The check 0 synchronising relay has limits of ±20 within which successful paralleling will be achieved. For stations with generator voltage switchgear, the unit transformer usually provides start-up supplies. However, the station transformer still supplies the station loads and the unit to station interconnection at 11 kV can provide a standby facility to the unit transformer (if it is out of service). Again, check synchronising facilities will be required to enable the supplies to be transferred without interruption. Details of the synchronising equipment are described in Chapter 12. 4.2 Shutdown and power trip There are basically two types of shutdown: • A controlled shutdown, due to a request for a reduction in generation or prior to an outage. • An emergency shutdown, following an internal or external fault requiring disconnection of the unit from the grid. 4.2.1 Controlled shutdown
A controlled shutdown is basically the reverse of a start-up sequence. The unit power output is reduced to a level appropriate to the design, when the unit and station supplies may be paralleled and all unit auxiliaries transferred to a station transformer source. In the case of a generator voltage switch arrangement, the supplies do not need to be transferred, providing a grid connection is maintained. Section 4.3 of this chapter describes what is the expected sequence of events following a loss of grid supplies. The AGR nuclear plant is arranged to have one generating unit associated with one reactor. The PWR differs in as much as present UK designs have two generators with one reactor. All nuclear plant requires post-trip cooling to remove the fission product decay heat, but due to differing reactor/turbine configurations, the functional requirements will vary from station to station. As post-trip cooling forms part of the safety function, it is quite normal to arrange for the emergency or essential system prime-movers to start for every reactor trip whether accompanied by loss of grid or not. 4.2.2 Power trip
There are a number of types of trip which may be experienced on power station plant. These are discussed briefly below and a more exhaustive treatment is given in Chapter 11: 32
Chapter 1 (a) Grid fault disturbances on the national grid system may cause a loss of connection to a single generating unit, or all power station connections. This is discussed in more detail in Section 4.3 of this chapter. An electrical fault may occur which requires the power station to grid substation circuitbreaker to open. (b) Generator system electrical faults in the generator unit zone, i.e., the generator, unit transformers and the main connections, will require both the generator HV and unit transformer LV circuitbreakers to open instantaneously. (c) Generator mechanical faults on the generator or turbine such as loss of lubricating oil or control fluid, loss of condenser vacuum, require shutdown of the unit, but not necessarily instantaneous electrical disconnection. Indeed some benefit can be gained in limiting turbine-generator overspeed if the generator is left connected to the off-site power system for a short time. (d) Electrical auxiliaries system faults on the electrical system at 11 kV or lower, may cause an unacceptable reduction in the plant necessary to continue running the unit. It should be noted here that the design philosophy is such that one fault should not cause the loss of more than one unit. (e) Consequential trip due to loss of steam generation, i.e., failure of the steam raising plant will require the unit to be tripped. Faults in group (a) above, normally subject the generator to 100 07o load rejection. The turbine-generator unit will accelerate due to the excess of input energy over demand. The steam (governor) and excitation (AVR) control mechanisms are designed to cope with this situation but some overspeed will occur, depending largely on the inertia constant of the unit and the speed of the control systems. Back-up overspeed protection, in the form of centrifugal force-driven bolts, is provided to trip the steam valves, should the control systems fail to control the unit below about 10 07o overspeed. Faults in groups (c) above, leave the generator electrically connected to the grid and the unit load, so that the overspeed due to entrained steam is limited. Completion of unit trip by disconnection from the electrical system is achieved by a power measurement relay detecting low forward power, see Chapter 11. In certain of the fault trip cases considered here, the auxiliaries system will be subjected to voltage and frequency transients. The safeguards are designed such that the mechanical systems are not subjected to transients outside their design codes. For stations with direct connected generators, faults in groups (a)-(e) will generally cause a loss of supply to the whole unit electrical system. Essential plant is supplied from battery-backed systems or by local generation using diesel generators or gas turbines.
System performance For stations with generator voltage switchgear, some faults in the above groups may allow the unit electrical system to remain connected to the grid system. Steam raising plant to generating plant intertrips are simple to design for steam generation/turbine units, as a trip of the steam raising plant will trip the aenerator and vice versa. For stations where common steam raising plant feeds more than one generating unit, logic lust be introduced to detect that only one nit has tripped if the design allows the Lienerating steam raising plant to ramp down to 50% load. This applies to th.: present design of PWR.
4.3 The effects of loss of grid supplies Loss of grid supplies is a generic term which covers events from the loss of a single generator connection, to the total collapse of the local grid network. Grid disturbances, which cause the voltage and/or frequency to go outside their operating limits, must also be considered in this category. The following sections examine the various mechanisms which lead to grid disconnections. A power station connected to the National Grid will experience all the voltage and frequency transients which occur on the surrounding grid system from time to time. From a system operation point of view, it is desirable to keep generation connected throughout these disturbances to support the system and its stability. However, the design and operation of generating plant will be specified to limits of voltage and Frequency in the station technical particulars. These li mits (as detailed in Section 5.1.(d) of this chapter) are those which are expected during normal operation. For conditions which may be considered abnormal, which will probably be outside the specified limits, the power station designer must consider deliberate disconnection of the station from the abnormal grid. This action is necessary to avoid possible overstressing of the electrical auxiliaries system or subjecting the mechanical plant to conditions outside its specified limits. This is of particular importance in nuclear plant which is nuclear safety-related, but is also of importance from an economic standpoint on conventional plant as repairs and outage time are very costly. In present nuclear stations, specific voltage/frequency detecting equipment is installed normally at the 11 kV voltage level, but may also interface with the essential system which may have its own specific dedicated monitoring equipment. Should the power station electrical auxiliaries experience conditions outside the preset limits for more than the specified time, automatic disconnection is carried out, the station is shut down and power is supplied from the essential supplies generator sets. Earlier CEGB power stations have their electrical protection arrangements designed such that faults which open the generator transformer HV circuit-breaker will
also trip the generating unit. Designs for AGR stations have specified that a 'run through' capability be provided. This means that on opening the generator transformer HV circuit-breaker only, thus disconnecting the generator from the grid, the generating unit will ramp down to house load. If the grid becomes available after a short time, the generator can then be re-synchronised without having to suffer the lengthy down times necessary to run up a machine after a hot or cold shutdown. This is of particular benefit since restarting is always a lengthy process due to Xenon poisoning in the reactor. In practice this operating regime has been difficult to achieve, mainly due to li mitations in the very rapid control of mechanical plant and/or the reactor at low power levels. Intended 'run through' periods of approximately 10 minutes have been aimed at with subsequent shutdown should grid supplies not be available after that time. To achieve this feature, it is necessary to arrange the electrical protection such that faults which need only trip the generator transformer HV circuit-breaker to isolate the fault, will not trip the unit or its connection to the electrical auxiliaries system. Certain grid disturbances local to power station sites in relatively weak grid areas, could cause the generators connected at the time of the fault to go outside their stability margin. This is because during the clearance ti me of the fault, the system voltage is depressed and no power export is possible. The excess energy is stored in the machine as an increase in rotor angle and may, dependent on the clearance time of the fault, cause the rotor angle to increase beyond its stability limit, resulting in pole slipping. Although the plant can be protected against this condition, the effect on the grid system from the consequent loss of generation is detrimental to its continued stability. Therefore consideration must be given to taking certain measures which will improve the transient stability of the generators in areas of weak grid connections. Several methods have been considered for adoption and basically fall into two groups: (a) Those which may be implemented on the turbinegenerator unit. (b) Those which may be implemented on the grid system. Methods in group (a) include fast-acting AVRs and possibly faster closure of the turbine stop valves, although this latter technique has not been proven on UK plant. Methods in group (b) include the addition of switched shunt reactors at 400 kV, automatic VAr compensation and static compensation. A new technique being investigated by the CEGB, is the addition of braking resistors connected at generator voltage. This is a method in group (a) where the resistors would be connected in the power station. 33
Electrical system design In this method, a large resistive load (approximately 300 MW) is connected across the generator .terminals for a very short period of time immediately following the fault clearance and hence voltage recovery. This gives the effect of absorbing the excess kinetic energy stored in the venerator rotor, avoiding the power swings which would otherwise occur. There is a need to identify the point at which the braking resistor is to be applied and the length of application. It is also necessary to use a switching device which is fast enough to be compatible with the detection method. The control scheme envisaged is based on an energy measurement system which constantly monitors the generator, and calculates in 10 ms time periods the energy and compares this against a preset value. The ti me at which the braking resistor is required and the length of application is calculated and the resistor switch is signalled to close. Typically a fault duration time of 85 ms would cause a braking resistor application in the region of 100 to 150 ms. A prototype has been designed and constructed for trial at Pembroke Power Station at a relatively weakly connected part of the grid. Preliminary indications are that this method will be more effective than shunt reactors for improving the generator's response to transient instability conditions. The loss of grid connection normally means the loss of electrical supplies to the unit (and possibly station) auxiliaries. Certain auxiliaries are required to continue in operation after unit trip to achieve a safe shut down state. For conventional power stations, the post-trip requirements are less onerous than for nuclear power stations. For conventional stations, battery-backed supplies or small diesel generators may suffice. The duty will include maintaining supplies to drives such as generator seal oil pumps or barring gear motors. Nuclear plant however, because of the decay heat due to fission products, requires more and larger drives to be maintained for longer periods of time. The posttrip requirements for most nuclear plant last for days rather than hours, and hence there is a need for a much more robust essential electrical system. As posttrip cooling is also claimed as part of the nuclear safety case, redundant plant is provided. A more detailed description of the post-trip requirements for AGRs and PWRs is included in Sections 3.3.3 and 3.3.4 of this chapter respectively. Previous nuclear stations based their safety cases on the ability to provide post-trip cooling without a grid connection being available. The various fault sequences were examined on a deterministic basis, and the case was made by demonstrating that there was sufficient redundant plant available to achieve the necessary safe shutdown state. The later AGRs and the PWR designs were examined using probabilistic analysis techniques using assigned values of component and system reliability to analyse various fault sequences against an overall target figure. 34
Chapter 1 In the case of the PWR, a predominant contributor to the overall frequency of degraded core was the fault group 'loss of all II kV'. The value of frequency for this fault group was found to be dominated by the frequency of loss of off-site power (LOSP), and detailed analyses were undertaken to determine the figure for LOSP frequency for the selected sites. The PWR safety case is made on the basis of, interalia, the estimated value of LOSP frequency. The frequency of LOSP is therefore a major consideration in assessing the reliability requirements for the on-site generation provided to meet the essential electrical system duties. The reliability assessment must consider the starting and continued running capabilities of the auxiliary generation to cater for the LOSP ti me bands such as those outlined in Section 2.4 of this chapter.
4.4 Station plant outages and faults There are two types of outage which have to be considered in the design of the power station auxiliaries system. These are:
• Planned outage The CEGB has a policy of regular maintenance for all power station plant. Although regular maintenance is normally carried out when the unit is shut down, there is often a requirement to maintain a supply to an associated piece of plant. This is particularly so when considering nuclear stations. Also some equipment may require maintenance more regularly than the unit outage period. To reflect these needs the design will normally incorporate sufficient diverse and redundant plant to a level necessary to maintain supplies to essential plant. • Forced outage Despite the regular maintenance policy, plant will occasionally become unavailable for example due to a fault. The repair of faulted equipment is known as 'breakdown' or 'urgent' maintenance. The defence against this occurrence, where it would compromise nuclear or plant safety, is to design the system with sufficient redundant items and supply routes to maintain essential supplies and enable equipment to continue operating. This is especially important for essential nuclear plant. The design principles to achieve the necessary level of security require plant systems to be provided as main and standby, separated or segregated from each other. Similarly, the electrical supply routes must be run separately or segregated, with the electrical supply, as far as practical, derived from independent sources. For the nuclear station essential systems, the level of redundancy required is much greater than for fossilfired plant. The present approach is to segregate plant, supply routes and sources, into functionally independ-
System choice ent groups or 'trains', each train having its own essential system generators. These are normally diesel driven generators connected at 3.3 kV, diesels being chosen for their high starting and operational reliability. For the PWR design, for example, a four train system has been chosen. Each train has a separation oroup allocated to it and all associated plant is physically separated from other train equipment. Auxilia y generator sets may be installed at a power station for he reasons given in Section 3.2.4 of this chapter. To meet the requirements for auxiliaries frequency support, 'peak lopping' and 'black start', auxiliary generators are fitted to the unit and/or station switchboards at 11 kV. Due to the ratings required to start up modern plant, they are likely to be gas-turbine generators. For the essential duty, due to the smaller load demands and more onerous response time and reliability required, diesel generators are nowadays used at 3.3 kV although gas-turbine generators have in the past been used to meet essential duties. As mentioned in Section 3.2.3 of this chapter, the essential system for the Sizewell B PWR, for example, has been chosen on the basis of four functionally independent trains, with a diesel generator connected to a 3.3 kV board on each 'train'. Each train is segregated from the others by fire barriers, and also all the equipment and cabling is segregated similarly.
5 System choice
the loss of more than one generating unit. This reflects the need to limit the generation loss to the system due to single faults. The connections to the grid site must also be examined to ensure that a single System or substation fault will not cause more generation loss than the System can tolerate. This is of particular concern in situations where more than one station is connected to a common substation. (c) Power plant designed and installed in the early 1960s assumed that grid loss could be tolerated and that the transmission system would not totally collapse. Subsequent events showed that a condition could occur which caused 'cascade tripping', i.e., power stations being tripped in an attempt to supply loads in excess of rating. This led to power plant being specified which could be started up in the absence of external grid supplies. For the 500 MW units, a twin Avon (25 -28 :v1W) gas-turbine generating set was used, but this was superseded at the later stations having 660 MW units by twin Olympus (35 MW) sets because of the need for a larger rating. The generator output voltage in all cases was nominally 11 kV and the gas turbines were connected to the II kV unit boards. Gas-turbine generators were installed for duties summarised as follows: • Black station starting
The gas turbine is run up and closed onto a dead busbar. Synchronising is only required for regular testing in parallel with the grid derived supplies. Gas turbines would normally be connected to the unit board.
5.1 Operational requirements
• Peak lopping
All power stations operated by the CEGB have their operational requirements set down by the CEGB's System Planning Department in the Station Development Particulars (SDPs). The choice of electrical system will be influenced by these requirements, the major aspects of which are discussed below:
• Frequency support
(a) Most nuclear fuelled plant is operated in a 'base load' regime especially as the output cost/kW from nuclear plant is cheaper than most fossil-fuelled plant. Coal-fired plant is, however, more adaptable to following the load demand curve. Clearly the electrical system must facilitate the operational flexibility where this is required. In nuclear power plant the overriding consideration is one of nuclear safety, and this is always uppermost in the designer's mind. The system chosen for nuclear plant must have an inherent ability to be configured in the most appropriate form for post-trip cooling, bearing in mind the alternative supply choices available. (b) The electrical system is required by the SDPs to be designed such that a single fault will not cause
-
As the gas-turbine generators have to be paralleled with the grid, automatic synchronising is provided. GTs would normally be connected to the unit board when the associated main unit is generating or via the unit/ station board interconnector to the station transformer when the main unit is shutdown,
The gas-turbine generator responds to falling frequency, starts, and is closed onto the busbar; this is specified to occur at frequencies down to 40 Hz and auto synchronising is required.
• Supplies to essential equipment
Supplies to essential drives such as generator seal oil, barring gear and, if a nuclear plant, electrical supplies to the post-trip cooling equipment.
The choice of rating, the number of gas turbines and their connection to the auxiliaries system, are all influenced by the duty required of them. Consideration must be given in the duty definition to the requirements for manual and/or automatic start, auto and/or manual synchronising, and for the inclusion of centralised control.
35
Electrical system design The first AGR nuclear stations were fitted with single Olympus gas turbines at 17.5 MW rating but these were for nuclear safety needs primarily, and were not intended for black start purposes, although some peak lopping duties were performed. (d) The plant must be designed to meet the voltage and frequency limits set by the system. Typically these are as follows: • All electrical plant must be capable of maintaining full CMR output within the range 49.551 H. From 49.5 to 47 Hz the output may be prorata with frequency, but operation below 48 Hz will not be for longer than 15 minutes. • Frequency excursions between 51-52.5 Hz may be experienced, but these will only be for short periods. • The HV system voltage to which the power station is connected is nominally 400 kV or 275 kV, with typical limits of: 400 kV, +5% 275 kV, +10% The electrical auxiliaries system must be designed to recognise these variations, as well as taking into account the drop in voltage throughout the system due to varying load and running conditions. Most modern conventional power plants have three main nominal voltage levels viz, ii kV, 3.3 kV and 415 V. The design limits of these voltage levels are typically from +6% to - 10% with -20% under motor starting conditions. The voltage at all nominal levels is maintained by means of optimising the transformer tap positions, such that the 415 V drive most remote from the primary (11 kV) busbar is subjected to a voltage within the tolerance under the worst condition, e.g., when starting. A check of the voltage profile under light load conditions is also made to ensure that the system is not overstressed. The design stage voltage profile is verified by system studies which model the system using interactive computer programs. These studies will of course need updating at a later date when all the manufacturers' data is known. This is described more fully in Chapter 2. 5.2 Reliability of main and standby plant The design of the electrical system should, in general, reflect the requirements of the mechanical plant and should not reduce its reliability. Where important mechanical systems are provided with redundancy, the electrical supplies should also be redundant. Therefore main and standby plant should be supplied electrically from independent sources, via segregated supply routes. 36
Chapter 1 For nuclear power stations, the mechanical and electrical plant may well require segregation, and will ultimately be segregated into independent functional 'trains'. This approach has proved to be the most robust system of providing defence against the whole range of credible faults, verified by probalistic analysis techniques. The use of diverse equipment in independent functional trains also benefits by reducing the impact of common mode and common cause failures. These techniques can be employed to provide the level of reliability required for the systems which are associated with nuclear plant. The reliability of a system will be analysed by the use of probalistic analysis techniques. To obtain a meaningful answer, the component reliability must be assessed. This is not always easy from a historical point of view, when components may have been in use only for a few years. However, by using equipment which has been rigorously and systematically tested, a certain degree of confidence may be obtained from the attributed component failure rate. Using a degree of pessimism in the calculations also expands the confidence factor of the figures used. Component failure rates are considered not only for normal conditions but also for abnormal conditions both natural and following major plant disruptions. This includes seismic events and extremes of pressure, temperature and radiation levels, and also missile impact. equipment is classified into items which are required to withstand seismic and environmental conditions and those which are not. Again verification is achieved by subjective testing. The choice of system will depend on the reliability required of it and the availability of suitable components. The use of proven equipment, which has demonstrated a satisfactory performance under varying conditions, will also support the predicted reliability of the system. New designs of equipment should be avoided in essential systems, unless they have been developed and tested to demonstrate standards of technical requirement at least as high as those claimed in the system design. The reliability of electrical systems is also enhanced by ensuring that designs follow the design principles as outlined in the introduction to Section 3 of this chapter. 5.3 Economics The choice of electrical system for a particular power station project will be influenced by several economic factors, the main aspects of which are discussed below. Capital cost
The initial capital cost of an electrical scheme can be estimated from a cost analysis of the various corn-
System choice ponents proposed. This can be achieved using data from many sources, for example: • Contract prices of similar equipment on other (preferably recent) projects. • Budget prices from possible suppliers or manufacturers. • Standar:I cost estimating databases. To enable a true comparitive estimate to be made, all prices aad costs must be related to a common price basis date. Any adjustment must be made using standard factors. Where designs are not finalised, a judgement must be made and an estimated cost attributed to it in the form of provisional sums, to allow for any variation from the base design. The CEGB employs a standard capital cost breakdown method for estimating new projects, where costs are allocated to particular coded plant areas. These costs are reviewed on a regular basis (usually annually) and updated as and when more firm information becomes available, e.g., tender prices or contract sums. In this way, close cost control can be applied to ensure that the project remains within the budget. In the early stages of a project, when designs are still subject to change, it is difficult to finalise the final electrical system due to the lack of confirmed information regarding the mechanical plant it is required to supply. However, by use of the estimating techniques mentioned above, it is possible to compare one proposed scheme with another for a particular duty so that the most cost effective scheme may be chosen.
urations will be examined to arrive at the most cost effective scheme. Some of the options which are likely to require examination are as follows: It is a policy to connect all modern new generating plant to the 400 kV system. The facilities available at the substation will determine whether a new 400 kV substation would be required or the existing equipment extended. It is also a policy to construct new 400 kV substations with metalclad gas-insulated (SF6) equipment, and if at coastal or polluted sites to enclose them within a building.
• Grid system voltage
• Station transformer primary voltage The station transformers may be connected at 132 kV, 275 kV or 400 kV. The choice depends on several factors as discussed in Section 3 of this chapter. The most economic option will normally be a 132 kV connection. The electrical load on the station transformers i mposed by modern power plant is considerable, it may therefore be necessary to uprate the 132 kV substation by the addition of an extra supergrid (400/132 kV) transformer to support the capacity required. This reinforcement of the 132 kV system, if required only to meet the new power station load, may make this scheme economically less attractive. Also the position of the 132 kV substation may require very long cable connections, again adversely affecting the scheme economics. Cost analyses showing these considerations will demonstrate which is the most economic proposal, but the final decision will be based on a combination of economic, technical and operational considerations.
Transformer losses Transformers associated with modern power stations are of ratings up to 60 MVA for unit and station transformers, and up to 1150 MVA for 900 MW unit generator transformers. Although designs are available which minimise the losses, they are still significant when taken over the life of the station. It is therefore present practice to include an estimate of the capitalised losses over the station life in the station cost estimates, Due regard to this element must be exercised in the choice of electrical system.
Consequential costs (connection to the National Grid) To connect the power station into the National Grid will require extra circuits to be used or provided at the transmission substation adjacent to the proposed site. In general, most substations have been in existence for some time and it is rarely a simple job to connect new generating plant to the existing system. The cost of the generation circuits, associated circuit-breakers, isolators, busbars and civil costs are attributed to the power station capital estimates. The costs for the remaining EHV equipment are attributed to the transmission account but, nevertheless, alternative config-
Development Whilst the CEGB policy is to use proven and tested plant, development work is often required to meet a need which has hitherto not been identified, The cost of this development work may be borne by the project and in that case a capital sum is included in the project estimates. The choice of system design may be influenced by the need to develop a particular piece of plant rather than use an existing alternative. In this case, a justification would have to be made to demonstrate the technical superiority compared with the cost of the development work. Sometimes development work is required because the previous equipment is no longer available, or is no longer manufactured, and there is no suitable alternative on the market. This situation often is not attributable to a particular project and would be funded from a general development budget.
Decommissioning At the end of a power station's life, it will require decommissioning or dismantling and the site prepared for other usage. 37
Chapter 1
Electrical system design For fossil-fired plant, this is a fairly straightforward exercise. For nuclear stations, however, the job is much more complex and protracted involving removal of fuel from the reactor, placing it into the cooling pond and finally removing it from site for processing. The costs of this work must recognise the need for an integrity and security of supply during fuel removal, as well as additional monitoring of the reactor structures whilst removing contaminated material after fuel removal. These costs will also be included in the station's capital estimates.
5.4 Plant limitations The electrical auxiliaries system must be designed to meet the needs of the mechanical plant, i.e., the starting, operational and protection needs of all the electrically-driven items. The problem the electrical system designer is faced with is twofold, firstly, the electrical system can only be finalised when all the parameters of the mechanical plant are known, and secondly, electrical plant itself has technical limitations which must be borne in mind. The following sections describe some of the major limitations which confront the system designer on modern power station plant. it is assumed that the major mechanical drives are known, at least in principle, and that a fair estimate of their load demand is available.
5.4.1 Switchgear current rating As mentioned in Section 3 of this chapter, the primary auxiliaries system voltage is largely determined by the largest electrical drive, normally the electric boiler feed pump. In the past, steam turbine feed pumps have been used, but the new coal-fired designs proposed for the 1990s are specifying full duty electrically-driven feed pumps in a 3 x 50% combination without turbinedriven pumps. For a subcritical pressure design of boiler the rating of each 50% pump motor is 13.5 MW. The decision to fit flue gas desulphurisation (FGD) on all new coal-fired plant and to retrofit it to some existing stations has meant a considerable increase in unit and station electrical load. The CEGB approved ranges of II kV switchgear have a maximum current rating of 3150 A. This leads to a maximum 11 kV transformer output of approximately 60 MVA. For station and unit loads in excess of this, consideration must be given to using more than one 2-winding transformer or, alternatively, the use of 3-winding transformers, i.e., transformers having two secondary windings. This will increase the number of switchboards at the primary voltage level, leading to more complex start-up/shutdown arrangements. An example of a calculation for maximum unit or station transformer rating is shown below. BS171 defines the method of rating calculation for transformers as: 38
Transformer rating =
J3 x 11 kV circuit-breaker current rating x open-circuit voltage of the transformer secondary winding.
Assuming a typical open-circuit secondary winding voltage of 11.5 kV and 3150 A, 11 kV circuit-breaker rating: Transformer rating =
x 11.5 x 10 3 x 3150 x - 6
10 = 62.57 MVA It is obvious that this rating is notional as the transformer cannot provide open-circuit voltage when on load. Hence the actual transformer capability is closer to the value obtained by using the transformer nominal secondary winding rating, i.e., Rating = -13 x 3150 x 11 x 10 3 x 1 06 = 60 MVA Similar constraints are imposed at other voltage levels by the limit of switchgear current rating, restricting the maximum transformer sizes accommodated by the system.
5.4.2 Switchgear short-circuit rating Normal start-up arrangements are such that the unit start-up supplies are derived from the station transformer and these are transferred to the unit transformer after the unit has been synchronised to the grid and part loaded. This requires paralleling of unit and station sources at 11 kV. Also, at lower voltage levels, paralleling may be required to changeover from one supply source to another should supplies need to be maintained to the connected plant. Paralleling at lower voltage levels, however, is not normally part of start-up procedures. The fault level at a switchboard is predominantly limited by the impedance of the supply transformer, although connecting cables also add to the source i mpedance, but not significantly. Whilst fed from a single source, the fault levels normally experienced are well within the rating of the switchgear. This however is not always the case when two sources are paralleled, but by adjusting the transformer impedances appropriately, the designer is normally able to arrange for parallel operation, especially at 11 kV. There are however other limiting factors, notably, the starting of large induction motors direct-on-line and the required system voltage profile. In extreme cases consideration must be given to the addition of inductors between switchboards, when parallel operation is required, to limit the prospective fault levels. These inductors may have to be designed such that they can be shorted out to avoid voltage drop problems under standby operation.
System choice For situations requiring additional generation such as for the emergency provision of essential power (by either gas-turbine generators or diesel generators), fault level problems may also occur. If the additional power enerator is connected in parallel with the grid or g another source of supply, care must be taken in the design of the electrical system to ensure that switchgear fault levels are not exceeded. Such paralleling may be required, fcr example, under peak lopping, frequency support, or testing conditions. An example of fault level calculations is shown in Section 5.4.4 of this chapter. 5.4.3 Large electric motors As mentioned in Section 5.4.1 of this chapter, the new coal-fired designs will have 13.5 MW boiler feed pumps. Motors of this size are difficult to start directon-line, due to the starting current experienced causing unacceptable voltage drops in the lower voltage systems. The designer is then faced with the conflict that the transformer impedances must be high enough to allow parallel operation while limiting prospective fault levels, but low enough to start large electric motors without serious voltage regulation problems. If no satisfactory compromise can be established, other solutions must be considered. The most likely avenue is to employ alternative starting methods for the large motors, or to achieve transfer of supplies without paralleling. Fast transfer In this method the unit and station supplies are transferred, but are not paralleled. The interruption time is sufficiently small that the motors do not slow down enough to be affected by re-energisation a few milliseconds after supply interruption. The use of presently approved air break circuit-breakers does not, however, give any confidence that consistent successful changeovers will be achieved with any degree of reliability. This is due to the relatively slow and inconsistent operating times of air break circuit-breakers. The use of vacuum circuit-breakers having much shorter operating times will overcome this difficulty and are now being introduced into power stations. Assisted motor starting
With the introduction of thyristor-based equipment, the speed control of motors has become very precise and many manufacturers offer standard systems. With motors of the size envisaged for the new coal-fired plant, static conversion equipment may require deelopment, but there do not seem to be any technical li mitations and this course would appear to be the most promising method of current-control starting of large motors. The additional space required for the static conversion equipment must be taken into account
when laying out the plant and the additional civil costs borne in mind. Another benefit of assisted starting of large motors is that the fault level contribution under 'making' conditions should be limited and may be negligible. If the design is near the switchgear rating limit, static conversion equipment will assist in reducing the fault level. A further benefit is the possibility of variable speed which may be of use for plant operation. Generator main connections The largest generating unit connected to the grid system in the UK is 660 MW. The new coal-fired plant will introduce larger units of about 900 MW rating. The present 660 MW generator voltage is 215 kV, with a full load current of 19 100 amperes. The proposal for the 900 MW design is to raise the generator voltage to 26 kV. The temperature rise allowed on the phase isolated busbars will limit the current rating on the present designs which, although they are rated at voltages in excess of 23.5 kV (voltage rating being 33 kV), are at the practical limit of current capacity with natural air cooling. The use of forced cooling methods will need to be considered, with sufficient redundancy to attain the necessary reliability. It is not uncommon to have to design the layout and fixing details of the generator end of the main connections to accommodate the particular wishes of the generator manufacturer. It is outside the scope of this section to discuss this in detail, but if the machine terminals do not have sufficient clearance to accommodate air-cooled phase isolated connections consideration must be given to the use of water cooled connections at least in part (see Chapter 4 on generator main connections). All these considerations have effects on the surrounding plant, e.g., the generator transformer will need to be developed to a suitably increased rating. This will affect the registered design concept which will need review (see Chapter 3 on generator transformers).
5.4.4 System performance calculations In order to assess an electrical system's performance fully, studies must be carried out using the interactive computer analysis programs described in Chapter 2 of this volume. These require a considerable amount of data to be gathered, which may be actual, typical or estimated values, but may not be available in the early stages of the electrical system design. The designer must check his provisional design by traditional hand calculations. A typical system is shown on Fig 1.19 and the typical calculations used to check the design are shown below. The unit system and station system may be considered as two separate systems for the purposes of fault level calculations. 39
Electrical system design
Chapter 1
400IkV
GPI° CONNECTION
GRID CONNECTION 400kV OR ;32KV
GENERATOR 'RANSFORMER
^JAIN 2ENF
STATION TRANSFORMER
I
g_N'T
PANFs7, 7,1EP
AUXILIARY
GENERATOR
TRANSFGRmER
UNIT BOARD
J ® (5
STATION BOARD
DDE
e
8
MOTORS CONNECTED AT kV ELECTRIC FEED PuMP • •3 SOW s C FAN 3 31,1 0 0 FAN 7 3M04• PAFAF,''MVA C VA P13 MP 3 - WV/ sGD EOGS7EB TAN 7MVIr
3 3kV UNI T AUXIOARY BOARD
STATION AUXILIARY BOARD
TYPICAL SYSTEM DATA 437Fv SWITCHGEAR FAULT EvEL RATING GENERATOR TRANSiENT REACTANCE DENERATDP TRANSFORMER IMPEDANCE UNIT TRANSFORMER IMPEDANCE STATION TRANSFORMER IMPEDANCE uNIT AuXIDAR , TRANSsORMER IMPEDANCE
= 35 077 OVA = 033 p u ON RATING OF 924 MW AT 085 Et = •EI! ON RATING OF '45 MVA ;7 5 , -; ON RATING OF AC /OVA = ,9 , • ON RATING OF BC MVA = 1 2', ON RATING OF 12 5MVA
FIG. 1,19 Typical electrical system parameters for a 900 N1W unit
Unit system
The unit system may be represented by a simple i mpedance diagram as shown in Fig 1.20, with the generator and grid being considered as two sources. This equates to the impedance diagram shown in Fig 1.21. The values of impedance are calculated as follows using a 100 MVA base: Zgrid
Assuming the maximum fault infeed is equivalent to the switch gear rating, viz 35 000 MVA, then the p.u. impedance on a 1000 MVA base is 100 therefore Zgrid = 0.0029 p.u. 35 000
7gen
Generator subtransient reactance is assumed to be 0.20 p.u. on a rating of 660 MW, therefore:
SOURCE GRID
Zgricl
Zgent
I mpedance on a 100 MVA base = 100 0.20 x x 0.95 = 0.0245 776 (where rating =
660 0.85
MVA = 776 MVA and allow-
ing a 5 07o negative tolerance) Zgen 40
0.0245 p.u.
FIG. 1.20 Impedance diagram for unit system
System choice
SOURCE GRID
SOURCE GRID
0 0029
Zgnd 0.0245
Zgen
0 018
Zgenl
Zut
FAULT Impedances in p u on 100 MVA Base
FAULT
FIG.
Zgent
1.21 Equivalent impedance diagram for Fig 1.20
FIG. 1.22
Typical impedance values for a 900 MW unii SOURCE GRID
Assuming the generator transformer to have an impedance of 16% on a rating of 800 MVA: 100 16 — x — x 0.9 = 0.018 p.u. 800 100 (where a 10% negative tolerance is assumed)
Zgent
therefore Zgent = 0.018 p.u.
Zut
Assuming a unit transformer impedance of 17.5% on a rating of 60 MVA: Zut
17.5
0 0245
0 0209
100 x — x 0.9 = 0.263 p.u.
60 100 where a 10% negative tolerance is assumed. therefore Zut = 0.263 p.u. Substituting these values into the impedance diagram shown in Fig 1.22. This simplifies to the impedance diagram shown in Fig 1.23. The equivalent impedance to the parallel branch is: 0.0245 x 0.0209 (0.0245 + 0.0209) = 0.0092 p.u.
FIG, 1.23
Simplified impedance diagram for Fig 1.22 41
Electrical system design
Chapter 1
Equivalent source impedance is (0.0092 + 0.263) p.u. = 0.272 p.u. The equivalent fault contribution for a fault on the unit board 11 kV where the circuit-breaker interrupts the fault is: 100 0.272
MVA
The 11 kV unit system fault contribution = 367 MVA (1.1) Additionally, if a circuit-breaker closes on to a fault, then the contribution from the motors and 3.3 kV system backfeed must be taken into account. This contribution is calculated as below.
/1 kV motor contribution The contributing MVA of a motor for hand calculations is assumed to be the ratio of the starting MVA to the MW rating and hence the value is obtained from the motor rating and the multiplication factor specified for motor starting in BS4999. For the purposes of the following calculation, a figure of 5.5-times for motors up to 10 MW and 5-times for motors greater than 10 MW is assumed. Typical figures for a 660 MW coal-fired unit would be: 1- D fan
contribution
= 2.3
x 5.5
-= 12.7
I D fan
contribution
= 3.3
x 5.5
= 18.15 MVA
PA fan
contribution
= 1.0
x 5.5
=
CW pump
contribution
= 3.75 x 5.5
= 20.6 MVA
Boiler feed pump
contribution
= 9.0
= 49.5
x 5.5
5.5
MVA
MVA
12.5 MVA transformer impedance on 100 MVA base 100 12.5 x p.u. 1 00 12.5 = 0.96 p.u. Therefore, total 3.3 kV to 11 kV impedance = 3.03 + 0.96 p.u. = 3.99 p.u. 1 00
3.3 kV motor contribution -
3.99
MVA
3.3 kV motor backfeed contribution = 25 MVA (1.3) The resultant fault level at the 11 kV unit board being considered is 529 MVA. This value is a symmetrical making duty that the switchgear must accommodate. It should be understood that the switchgear is rated on a making first loop current peak which assumes a value of 121 kA. The equivalent RMS symmetrical figure (expressed in MVA for convenience) is calculated as follows: 121
121 kA peak is equivalent to
-
kA RMS, but
to calculate the RMS value of the absolute peak of current at the instant of initiating a short-circuit, a further factor of 0.9 is applied. Symmetrical RMS equivalent is
121 0.9 x 2V2
kA
= 47.54 kA
MVA
This equates to an equivalent MVA value of The 11 kV motor contribution is therefore calculated by considering the number of motors connected at the ti me of the fault. For this example it is assumed that the following drives are connected 2 ID fans + 2 FD fans + CW pump + BFP + PA fan (36.3 + 25.4 + 20.6 + 49.5 + 5.5) = 137.3 MVA (1.2) In addition, the contribution back fed from the 3.3 kV Unit Auxiliary Boards must be taken into account. Assuming that a typical 3.3 kV unit load is 6 MW fed through a 12.5 MVA 12%, 11/3.3 kV transformer:
3.3 kV motor contribution
3.3 kV starting MVA -= 6 x 5.5 (assuming a starting MVA/MW ratio of 5.5) = 33 MVA on a 100 MVA base, equivalent impedance =
100 33
- 3.03 p.u. 42
x 11 x 10 3 x 47.54 x 10 3 = 905 MVA A value of 900 MVA is chosen for calculation purposes as a notional MVA value. The figure of initial peak current values are unlikely to be seen in practice due to the relatively slow operation of the switchgear and the fact that the fault current will decay during the switch operating period. Also the voltage is depressed at the time of the fault and the notional value is unlikely to be achieved.
Station transformer system The station transformer fault contribution is calculated in a similar manner to the unit system. The station system may be represented by the simple impedance diagram shown in Fig 1.24. Zgrid may be assumed to be the same value as used for the unit calculation, viz 0.0029 p.u. This assumes that the station transformer is connected at 400 kV. However, Zgrid for the 132 kV system when combined with the station transformer impedance will result in
System choice 39.4 kA with an enhanced making capability of 121 kA first peak. These values equate to 750 MVA break and 900 MVA make, symmetrical, but will be tested to the current value. The combination of power sources which may be paralleled is limited by these ratings. The system must be examined for the proposed operating conditions and the fault contributions determined. An example of one of the most onerous operating conditions is when the unit board is paralleled with the station board during start-up and shutdown. For this condition the infeeds from contributions (1.1) to (1.5) (inclusive) are summated and may be shown diagrammatically as in Fig 1.25.
SOURCE GRID
Zg d
zst
UNIT TRANSFORMER FiG. 1.24 Impedance diagram for a station system
a lower fault contribution. Therefore choosing 400 kV w ill give the worst case. Station transformer impedance (Zst) — assumed to 0 be 18 70 on rating of 60 MVA: 18
WO
100
60
Zst — x
x 0.9 (assuming 10°7o negative tolerance)
= 0.27 p.u.
3 3kV
(UNIT)
Total impedance = 0.27 + 0.0029 p.u. =- 0.273 p.u.
Fic. 1.25 Fault contributions from various sources in MVA
Fault contribution from station transformer 100
— 366 MVA
(1.4)
0.273 3.3 kV motor
contribution Assuming a station load of 5 MVA on the 3.3 kV system, starting MVA (assuming a starting MVA/MW rating ratio of 5.5) = 5 x 5.5 MVA = 27.5 MVA Assuming a 12.5 MVA unit auxiliary transformer feed to the station auxiliaries load (at 123/4 on rating), the 3.3 kV station auxiliaries motor fault contribution is:
100 12 100
x
100 12.5
21.7 MVA
MVA +
3.3kV (STN,
100 27.5 (1.5)
The resultant fault level of the 11 kV board being considered is 388 MVA.
'Breaking' fault level = 367 + 366 MVA = 733 ' Making' fault level = 733 + 137 + 25 + 22 = 917 MVA This 'make' fault level figure is in excess of the symmetrical fault level rating of 900 MVA. A significant contribution is made by the motor infeeds which are based on pessimistic values. In reality the values used have not taken account of the initial decrement caused by the X/R ratios during the first half cycle which have a modifying effect by a factor of the order 0.9. Also, no allowance has been made for the additional impedance presented by the connecting cables. This again would justify a reduction by a factor of 0.95. Therefore the motor contribution value is more realistically: (137 + 25 + 22) x 0.9 x 0.95 = 157 MVA
Calculation of fault infeed for various conditions
The maximum symmetrical fault level rating of 11 kV switchgear approved for use on the CEGB system is
The total 'make' fault level therefore becomes: (157 + 733) = 890 MVA 43
Electrical system design
Chapter 1
This value is very close to the maximum switchgear rating and would require corroboration by computer system studies as described previously. When carrying out the initial hand calculations, if it is found that the fault levels are considerably greater than the capabilities of the system components, then a review of the influencing parameters should be carried out. Amongst these are the transformer impedances and tolerances applied. This may result in specifying closer impedance tolerances when purchasing the transformers. Auxiliary generation
Auxiliary generation may be required, for example, to start up the station without external supplies, i.e., 'black start'. In this case, the auxiliary generator is assumed to be connected to the station 11 kV board. The impedance diagram is therefore as shown in Fig 1.26.
Fault contribution
—
100
MVA
0.176 = 566 MVA Therefore, there is no problem in paralleling the auxiliary generator with the grid when restoring the system to grid-fed station transformers.
5.5 Maintenance and safety Safety of plant and personnel, which assumes prime i mportance in power stations, may be considered under two plant states, i.e., operational and maintenance. Section 8 of this chapter describes in more detail the methods adopted to achieve the objectives, but the considerations can be outlined as follows. 5.5.1 Operational
The main concerns under this mode of activity are: • Avoiding damage to the plant. This can be caused by putting the plant into a state whereby continued operation or the response to a fault condition would cause permanent damage to the plant. An example of this would be the paralleling of two electrical supplies which would subject the switchgear to short-circuit conditions outside its rating, were it asked to clear a fault.
SOURCE GRID
• Avoiding hazards to personnel. In the example quoted above, there is also a danger to personnel operating the plant and hence another fundamental reason for protecting against it.
Flo. 1.26 Impedance diagram for an auxiliary
generator connected to the station board
Assume auxiliary generator (GT) having a rating of 30 MVA at 15 070 sub transient reactance: ZGT
1 00 = - X
5.5.2 Maintenance
0.15 p.u.
30 = 0.5 p.u. Zgrid
= 0.0029 (from previous)
Zst
= 0.27 (from previous)
Total impedance
0.2729 x 0.5 (0.2729 + 0.5) = 0.176 p.u.
44
Protection is primarily afforded by interlocking, generally referred to as operational interlocking, and is achieved by either an electrical relay scheme or a computer based scheme. The choice is largely based on the complexity of the system being interlocked, as the electrical relay based scheme becomes extremely ponderous and difficult to design when there are a large number of possible operational configurations to consider.
P.U.
The concern under this mode is essentially personnel safety. Plant damage is of course possible and must be considered, but less likely due to the plant being nonoperational during maintenance. Essentially, the objective is to allow safe access for maintenance purposes to electrical equipment, which is normally alive. Access is controlled by a rigid set of safety rules specifically drawn up and controlled by the CEGB, under a formal 'Permit for Work' system. To ensure that access is denied until all electrical apparatus has been switched off, isolated and earthed,
System choice it is normal to apply a coded key system designed for each application. 5.5.3 Other safety interlocking
During normal operation it is imperative that all equipment which contains live metal must be designed such that access is denied at all times whilst the equipment is enei c;ised. Typical examples of this are switchgear cubicle where internal access is prevented when the isolator is ION', done by ensuring that the isolator interlocks with the door opening mechanism. Although these requirements are written in the equipment specification, there are several ways they may be achieved. The choice must be one of a balanced design while ensuring safety allows equipment operation without undue restriction. 5.5.4 Nuclear safety
Although the above requirements apply equally well to nuclear plant, the systems which have nuclear safety connotations will be designed with a higher integrity than their fossil equivalents. In many cases, however, this does not lead to the scheme being more complex, as the simplest and most cost effective way of achieving the operational and personnel safety requirements will often prove to be robust enough to withstand a higher analysis standard.
5.6 Quality assurance Quality assurance (QA) may be considered in two parts, there being design quality and product quality. 5.6.1 Design quality Quality assurance structure
The CEGB has always taken great care in the design of its power stations, with due regard for the specified requirement of a 30 year life from the plant. This is based on the cost of ensuring high reliability and availability, compared with the economic penalty of a high merit unit outage. More importantly, the design of nuclear plant has been given even more rigorous scrutiny in order to attain the high standards required to satisfy the Nuclear Installations Inspectorate (NII). In order to improve further the quality of the design, the CEGB has adopted the requirements of BS5882 (Nuclear) and BS5750 (Conventional) to formalise its approach to quality assurance. To manage the design process on the current nuclear projects (e.g., PWR), a set of auditable project procedures have been written to cover all the activities of the project team and any design/supply support required from outside the team. Each person involved in a particular activity will be issued with the relevant procedures relating to it and will be required to work
to them. Fossil fuel plant design will be covered in a similar manner, but to an appropriate and less rigorous standard. The design process
The essence of controlling the design process is to ensure that: • All specialist and interface departments have an opportunity to input to the design where their disciplines are involved. • The design proceeds in accordance with the laid down design strategy. • The design can be completed within the project programme. • The design selected is economically justified. • All aspects of the design process are documented and made available for the life of the station. To achieve the above, it is necessary that for each topic a design strategy is in place, so that each designer has a common design base from which to proceed. At each stage of the design, the design statement, be it document or drawing, will need to be verified. This will be achieved by the 'verification process'. Verification is achieved by initially circulating a 'plan' of who will be required to review the document or drawing. The plan will be created at an early stage and will be with the document or drawing throughout the whole life of the design. The document or drawing is circulated to each reviewer identified on the plan. Comments received from reviewers must be considered by the originator, who must agree with the reviewer how to resolve the comment. Each document or drawing will have a 'Fitness for Purpose' reviewer, who has the job of ensuring that the document or drawing fulfils the intended purpose and follows the laid down project strategy. Each document or drawing will have a record sheet indicating the reviewers involved who will sign the sheet after agreement is reached. In this way each stage of the design is reviewed, with any issues which are unresolved being identified clearly at each stage. Periodically the QA of each section of the project will be audited to identify whether the procedure is being violated and point out any corrective measures necessary. Independent design audits will be carried out at regular intervals to ensure that the design is proceeding at the required standard. Any corrective measures would be suggested at this point. Coding and numbering
The development of modern computer databases has led to much more flexible data handling systems being available. The large number of items of plant, docu45
Chapter
Electrical system design ments and drawings associated with modern power plant has led to a need for quick and accurate identification of plant and documents. A system is therefore required which will uniquely 'number' and also 'identify' the plant/documentation. Identification of plant items will use system based codes, with additional coding to identify function, location, separation group, etc. Several numbering/coding systems are used both in Europe and the USA. The CEGB is developing a 'next generation' system which will employ the best features of the existing systems, with due regard to the power of the computer systems available. 5.6.2 Product quality
The quality of the manufactured product supplied by CEGB contractors for many years has been very high. This is ensured by constantly monitoring the performance of contractors, the use of an 'approved list of tenderers' and, where appropriate, developing designs and specifications jointly with prospective tenderers. New products, if being considered, are assessed by the CEGB on a technical and commercial basis as are the manufacturers concerned. All vendor assessments of this nature are strictly confidential to the CEGB. The quality of the product is largely dependent on the quality of the technical specification and the ability of the manufacturer to adhere to it. The CEGB operates a very comprehensive product inspection procedure during manufacture which ensures that the product quality is satisfactory. The technical specification will call for all necessary routine and type testing of equipment to ensure that it meets the technical requirements. Standard technical clauses have been developed by the CEGB to ensure that the product quality is repeatable, whichever contractor is chosen for a particular piece of plant.
• Those which because of stringent supply requirements would not give an adequate level of reliability if operated from the electrical auxiliary system only. • Those which are required for the main unit shutdown. DC supplies are preferred for this purpose because they offer better reliability. • Those which are essential for 'black start', i.e., in the absence of normal AC supplies.
6.2 Earlier UPS and GIS schemes Before 1978 both battery-backed motor-generator sets and static inverters were used at various power stations to provide the UPS systems. Both types of system were generally unreliable and the various problems experienced can be summarised as follows. 6.2.1 Motor generator (MG) set schemes -
A typical motor-generator scheme is shown in Fig 1.27. The disadvantages which emerged in service were: • Frequent maintenance required, e.g., shutdown and inspection every 3 months. • Excessive brush wear. • Parallel operation difficult at low loading. • Unreliable frequency locking to the station master clock. • Too many components used, resulting in high failure rates (MTBF of 2 years for a single MG set). 6.2.2 Static inverter schemes
6 Uninterruptable power supply ( UPS) systems
Static inverters have been in use for over 17 years on large CEGB power stations for supplying power to instrumentation, controls, computers, alarms, etc. The subsequent developments of schemes used before 1978 were based on the shortcomings which appeared during their operational years, namely:
6.1
• Too many components used, resulting in high failure rates (MTBF of 2 months for a single inverter).
introduction
The UPS systems, formerly known as guaranteed instrument supplies (GIS) or no-break supplies, are designed to provide battery-backed AC supplies of better quality and continuity of service compared with the supplies available from the electrical auxiliary system. They are provided for essential instruments, controls and computers, which are associated with the safe and reliable operation of the plant under all normal and abnormal operating conditions. The following loads are usually supplied from the UPS systems: • Those which are required for post-incident monitoring and recordings following a main unit trip and loss of station AC supplies. 46
• Ferro-resonance problems when switching transformers onto inverters. • Load sharing difficulties as well as single inverter failure caused tripping of all inverters and a total loss of instrument supplies. • Excessive component temperature rise leading to premature failures. • Poor short-circuit capability. Each of these early schemes, illustrated in Figs 1.28 to 1.32, is described briefly as follows with details of shortcomings:
Uninterruptable power supply (UPS) systems
415V 3 PHASE STATION SERVICES BOARD
415V 3 PHASE UNIT BOARD
TRANSFORMERS
RECTIFIERS BATTERY
BATTERY
11 110VDC STANDBY MAINS SUPPLY MOTOR STARTERS
MOTOR GENERATORS
1 I (SEE NOTE) 1 /
110V AC SINGLE PHASE
SUB-BOARDS OR RING MAINS OR (NUMBER OFF DEPENDS ON SITE LAYOUT)
ilJ CD NORMALLY OPEN
NOTE: CIRCUIT BREAKER CAN ONLY BE CLOSED IF THE THREE MG SET CIRCUIT-BREAKERS ARE OPEN
Fic. 1.27 Motor generator scheme — single line diagram of connections
(a) One inverter per 500 MW generating unit
The load was normally supplied from the unit electrical auxiliary system via a step-down 415 V/110 V single-phase transformer shown in Fig 1.28. In the event of mains failure the load was transferred to the inverter. The scheme did not prove reliable due to inverter failures. The 240 V DC supply was derived from the 240 V DC station system used to supply emergency DC drives, emergency lighting, switchgear and clos-
ing solenoids, etc. (b) Two inverters per 500 MW generating unit One inverter supplied the load with the other on 'cold' standby as shown in Fig 1.29. The DC system was dedicated to the inverters. In the event of mains failure the load was fed from the inverter, which was supplied from the battery. If the inverter failed, the changeover contactors transferred the load to an alternative supply derived from the electrical auxiliary system. 47
Electrical system design
Chapter 1
TO UNIT 1 C & I SWITCHBOARD
FIG, 1.28 Static inverter scheme (one inverter per main unit)
The scheme proved reasonably reliable, but over-elaborate and consequently more expensive compared with present practice. (c) Four inverters per 660 MW generating unit Three inverters operate normally in parallel and one on standby as shown in Fig 1.30. The scheme was designed such that two inverters could supply the total load. The DC system was dedicated to inverters and was on a per unit basis. The inverters proved very unreliable and the design did not achieve inverter redundancy, i.e., on failure of one inverter the other inverters could trip. The standby supplies derived from the electrical auxiliary system had to be used on many occasions due to tripping of all inverters. The equipment was eventually disconnected and a new development single UPS installed. (d) One inverter per 660 MW generating unit A DC system was dedicated to it as shown in Fig 1.31. In the event of inverter failure the load was transferred to an alternative supply using changeover contactors. The main disadvantages of this scheme were: • Interruption of supply on transfer from the 48
inverter to the alternative supply and vice versa. • On transfer from the alternative supply to the inverter large inrush currents occur on the load side. Low inrush transformers were subsequently fitted to avoid the problem, i.e., to prevent inverter ferro-resonance and trips. • The scheme reliability was not adequate. (e) One inverter per 500 MW generating unit A DC system was dedicated to it as shown in Fig 1.32. The scheme offered considerably improved reliability compared with the previous scheme (Fig 1.31), because a static switch was provided to transfer the load without interruption on inverter failure; also on re-transfer from the alternative supply to the inverter. A number of inverter trips occurred during grid disturbances. However, the present version of this type of equipment has given very little trouble.
6.3 Development of UPS systems In order to overcome the previous service difficulties a 30 kVA, 415 V single-phase development static UPS system (Fig 1.28) was commissioned in May 1978 at
Uninterruptable power supply (UPS) systems ■■■=,
.
■•■■■••■■••■•■•
FIG. 1.29 Static inverter scheme (two inverters per main unit)
Drax Power Station together with low inrush (Sli mes full load current) 8 kVA, 415/110 V distribution transformers. The system has proved entirely satisfactory. Further identical UPS systems have been commissioned at Littlebrook D and Drax power stations and similar 3-phase and single-phase systems have been commissioned at Heysham 2. For the Littlebrook D and Drax systems, the inverter alone is capable of clearing a short-circuit fault of a 415 V branch circuit protected by a 25 A fuselink to BS8802, Class Q1 , within 4-5 cycles. The static switch is double-pole and is rated at 1000 A RMS for five cycles. With assistance from the bypass supply, the above fuselink can be operated in less than 5 ms when clearing a branch short-circuit. The rotary maintenance bypass switch is solenoid bolt-interlocked to prevent out of synchronous transfer. The complete equipment was type tested; the tests included vibration tests, dry heat, damp heat and low temperature tests, followed by a 200 hours long term stability test on full load.
The step-down transformers have the following basic parameters: • I mpedance 2%. • Flux density of approximately 0.75 T. • Inrush current when energised from mains of approximately 100 A peak at 415 V, decaying to full load current in 10-12 cycles. The inrush current was obtained using a point-on-wave static switch. A high performance lead-acid Plante battery is rated for 30 minutes' standby duty at 15 ° C ambient temperature. 6.3.1 Littiebrook D power station schemes
Unit GIS system There are three 660 MW oil-fired units at this station. Each unit has an inverter system including a lead-acid battery, 415 V unit GIS switchboard and a distribution network as indicated on Fig 1.33. Only the unit loads 49
Chapter 1
Electrical system design
415V 50Hz
STAND-BY BATTERY CHARGER
415V 50Hz STAND-BY SUPPLY
415V 50Hz STA NO-BY SUPPLY
415V 50Hz
415V110V
FIG. 1.30
Static inverter scheme (four inverters per main unit)
are connected to this system. (In order to minimise discharging the battery, the charger is normally supplied from the essential/station system on more recent schemes.) Each inverter system has the following main components:
from the 415 V unit switchboard B. Under normal operating conditions the power flow to the loads connected to the GIS switchboards is as follows:
• Charger.
• Inverter.
• Battery (rated for a 30 min standby duty).
• 415 V unit GIS switchboard.
• Inverter.
• Step-down transformer.
• Static switch.
• Changeover contactor.
• 415 V unit switchboard A. • Charger.
• Maintenance bypass switch as shown on Fig 1.34. The charger supply is derived from the 415 V unit switchboard A. The inverter bypass supply is derived 50
In the event of failure of the charger supply, the load continues to be supplied by the battery. If the supply to the charger is not restored within approximately
Uninterruptable power supply (UPS) systems
415V 50Hz
415V 50Hz
REGULATING TRANSFORMER
110V5H
FIG,
1.31 Static inverter scheme with an electromechanical changeover switch
FIG.
half an hour, the inverter system is arranged to transfer he load to the inverter bypass supply automatically and without interruption upon detection of the low battery voltage. The load is also transferred automatically from the inverter to the bypass supply under any of the following conditions, providing the inverter is synchronised in both phase and frequency to the bypass supply: • Inverter failure or output voltage outside the set tolerances. • Excessive inverter overload or load inrush current. • Short-circuit on the load side. A break in the supply is expected when transfer is caused by a fault on any of the outgoing feeders. The GIS system is designed to minimise the break (less than 10 ms), except on the rare occasions when changeover contactors are used at the load centres. Under normal operating conditions the inverter is synchronised in both phase and frequency to the bypass supply to enable an interruption-free transfer to take place.
1.32 Static inverter scheme with regulating transformer
Local distribution units are provided for each 110 V single-phase supply point, each comprising two singlephase main and standby transformers, changeover contactors, switches and distribution switchboard as indicated on Fig 1.35. These are located around the station, in the control block, etc., at suitable load centre positions. Each 110 V AC GIS switchboard has an automatically connected standby supply arranged via changeover contactors. Changeover contactor units comprise two adjacent circuits, arranged to give the highest practicable intercircuit segregation to permit work in safety on one circuit whilst the other remains live. The contactors are capable of picking up and sealing home with any incoming supply voltage between 75% and 110% of the rated value. The voltage limits apply over a frequency range between 47 Hz and 51 Hz. Breaks in supply of up to 10 milliseconds should not cause the contactors to drop-out. The two contactors are interlocked to give either a 'main' supply or a 'standby' supply, i.e., avoid parallel operation of the two supplies. Transfer from the 'main' supply to the 'standby' supply is initiated and completed automatically for 'main' supply voltages below 80% of the setting value. An undervoltage relay is provided for each load centre for this purpose and its 51
Chapter 1
Electrical system design
415V STATION BOARD
1 415V 50Hz
LOAD CENTRE
110V 50Hz
FIG,
1,33 Littlebrook D power station — unit GIS
operating characteristics are such that the minimum operating time at zero voltage is not less than 10 ms. The voltage setting range is adjustable in seven equal steps between 40 07o and 80 07o of the nominal voltage. On complete loss of the 'main' supply for longer than 10 milliseconds, the transfer to the 'standby' supply takes place such that the total voltage break time on the load side does not exceed 100 ms. Transfer from the 'standby' back to the 'main' supply is manually initiated following the 'main' supply restoration. The initiation is from the 415 V unit GIS switchboard location and is made in stages to avoid excessive inverter overload, which may arise due to inrush current of the step-down transformers. The total voltage break time on the load side does not exceed 100 ms. The standby supply is derived from the 415 V station switchboard. This supply is also used for those unit loads which require two AC inputs from diverse sources combining them within the equipment in DC form. The 415 V bus section switch is intended to be closed 52
110V 50Hz
only if a prolonged outage of the incoming 415 V unit GIS is expected. The system is designed to give acceptable security even during the inverter outage for repair, i.e., two diverse AC supplies are normally available. The computer system is not designed to tolerate 100 ms breaks, but it is not essential for unit operation. All other loads are either designed to tolerate a 100 ms break in supply or have duplicate AC inputs and power packs to achieve the high level of reliability required. The GIS system is designed to achieve a reliability target of no more than one main generating unit trip in 30 years of operation. Only one inverter system is provided on each unit GIS system, but in the event of inverter failure automatic transfer to another AC supply occurs, i.e., a standby redundancy is provided. The standby supply is not battery-backed. The outage time for an inverter is small and it was not considered necessary to provide a second inverter to cover for the small outage times involved. These are based on pessimistic figures of the mean repair time
Uninterruptable power supply (UPS) systems
STATIC SWITCH
a
I a I
POS ■ TiON IA
OF
I I MAINTENANCE BY-PASS SWITCH
N NORMAL POSITION N'ENANCE POSITION
A T PASS SUPPLY
50,1Z NOMINAL RED &BRIE PHASES ONLY
TO 4 , 5V (g LAYN v T EvE DB N I FTt um ENT
Fic. 1.34 Littlebrook D power station — unit GIS illustrating maintenance by-pass switch
being 48 hours. In order to minimise time to repair
a faulty inverter system a spare set of inverter system
components is provided. Station GM system The station GIS system has two inverter systems, each including an associated lead-acid battery, 415 V station GIS switchboard and a distribution network as indicated on Fig 1.36.
Either of the two inverter systems is capable of supplying the total normal station load and each battery is rated for a 30 min standby duty. This makes it possible to operate with one out of service if necessary. Under normal operating conditions the load is shared as equally as possible between the two inverter systems. Transfer of the load from one inverter to another is only possible with a break of up to 100 ms, using the changeover contactors on the local distribution units. 53
Chapter •
Efectrical system design
UNIT GUARANTEED INSTRUMENT SUPPLIES DISTRIBUTION BOARD
I
OFF 0
0
STAND. INORMAL BY
• • VI
If
•
BY •
STAND
mAtiN
I
• • _
FIG. 1.35 Unit GIS distribution switchboard
Local distribution units are provided for each 110 V single-phase supply point, each comprising two singlephase main and standby transformers, changeover contactors, switches and distribution switchboard as indicated on Fig 1.37. These are located around the station at suitable load centre positions. Each 110 V AC GIS switchboard has an automatically connected standby supply arranged via changeover contactors. The changeover scheme is almost identical to that previously described in the unit GIS section, except that a supply priority selector switch is provided. Following a loss of supply from an inverter and its associated bypass supply, the 415 V interconnector can be closed if a prolonged outage is expected. The load 54
distribution units affected are then transferred back to
the 'main' supply in stages. 6.3.2 Drax power station schemes
There are six 660 MW coal-fired units at this station,
also six 35 MW gas-turbine generators. Unit GIS system Following the problems experienced with the original scheme fitted to the first three units (Fig 1.30), a 30 kVA development inverter was installed on Unit 2 in 1978. The inverter system is identical to the Littlebrook D power station type. The unit system for the first 3 units is basically identical to the Littlebrook D power station unit sys-
Uninterruptable power supply (UPS) systems
415V 50Hz
415V 50Hz
30kVA
415V 50Hz
LOAD CENTRE
1 OV 50Hz
Fla. 1.36 Littlebrook D power station — station GIS
tem. Units 4, 5 and 6 have two separate inverter systems per unit, one for the computer and the second for all other loads. The total unit load was estimated to be in excess of one 30 kVA inverter already developed and proved on Unit 2, hence the reason for two systems per unit. Station GIS system
This is similar to the scheme previously described for the Littlebrook D station GIS in Section 6.3.1. Gas turbine inverters
Each gas turbine has a separate single-phase inverter of less than 5 kVA with 110 V output and 110 V DC input. These supplies are required to enable the gas turbines to start in the absence of normal AC supplies. 6.3.3 Heysham 2 power station
This is an advanced gas cooled reactor station with two reactors and two 660 MW generating units. The UPS systems can be broadly divided into two groups:
• Essential UPS systems, i.e., those required for normal reactor operation and those which are necessary for post-trip cooling of the reactor. • Non-essential UPS systems, i.e., those which are not safety related. These are described in the section on unit and station UPS systems later in this chapter. Each reactor is arranged into quadrants, each quadrant having two diverse modes of reactor cooling called X and Y. Consequently each quadrant has four independent UPS systems. The UPS system associated with one quadrant is shown on Fig 1.38. 415 V essential UPS system X The UPS system rating is 100 kVA and the output is 415 V. 3-phase and neutral, 50 Hz (nominal). Only essential loads are connected to this system. These are mainly control and instrumentation loads and various motors and valves. The previous advanced gas cooled reactors used motorgenerator sets for this duty. 55
Chapter 1
Electrical system ds
ci) STATION GUARANTEED INSTRUMENT SUPPLIES DISTRIBUTION BOARD
(1
FIG. 1.37 Station GIS distribution switchboard
The system has been fully type tested to very stringent requirements, including seismic tests and 11 kW motor direct-on-line starts. The UPS battery is capable of supplying the full UPS load for considerably longer than the 30 minutes specified. 110 V essential UPS system Y
This system is designed to provide both 110 V AC and 110 V DC supplies. The inverter is rated at 6.3 kVA, 110 V, 50 Hz and DC output is rated at 50 A continuous load. The loads are mainly various control and instrumentation supplies. A standby battery and charger are provided, which can supply the inverter and DC loads of the Y 'train' 56
or 110 V DC loads of the X train, This equipment is also seismically qualified and in order to minimise the common-mode failure probability diverse equipment is provided for the X and Y UPS systems. Non-essential UPS systems
Unit and station UPS systems which consist of four 150 kVA, 415 V, 50 Hz single-phase UPS systems are provided at this station. Each is made up of 3 x 50 kVA inverters, a 600 A, 360 V DC battery charger and a 200 kVA static switch. The system can be expanded to 200 kVA by adding another 50 kVA inverter and another battery bank for which the stands are already installed. Inverters operate in a redundant mode of operation providing that the load does not exceed 100 kVA limit
Uninterruptable power supply (UPS) systems
41ST ESSENTIAL SERVICES BOARO
4 , 55 ESSENTIAL SERVICES ECAEIC.
-
-
Ay
it$
NOT TALLY
"5:,' ESSENTIAL LINI:%7EP.R.,PT.BLE POWER SU.PLY LAY
OPEN
'2
12 , 55 , ALA STANDBY TO X OR Y SYSTEM
.,--doro
•
3.
Or
1'05 ESSENTIAL STANDBY BATTERY LA
To ,• Dv DC ESSENTIAL BOARD LAX
• 5N 50Hz 3 PHASE A NEUTRAL
60Hz SINGLE PHASE 63 K yA
11
ESSENTAL AC DR,vES
NORMALLY OPEN 11
11 II
11 0
05 DC
• ESSENTIAL BOARD
11 II
7
AY
II
•
1
I
"
A,
ESSEN -71AL LAS E.:',39,=
II 11 II II 11
5 ' 5.?N GLE PHASE
ooLiaLE Pc,E
1105 50Hz SINGLE PHASE DOUBLE POLE
NOTE. ESSENTIAL UPS SYSTEM REPEATED EON EACH QuA0HANT
FIG. 1.38 Heysham 2 power station — essential X and Y UPS systems
(or 150 kVA when up-rated to 200 kVA). The scheme is illustrated on Fig 1.39. Unit UPS system Each unit has an UPS, 415 V, 50 Hz, double-pole unit UPS switchboard and a distribution network. The maximum step-down transformer rating is 16 kVA and the loads are switched-in sequentially to avoid excessive inrush current and undesirable transfer to the bypass supply. The following loads are supplied from this system: • Those which are required for post-incident monitoring and recordings following a main unit trip. • Those which because of stringent supply requirements would not have adequate reliability if operated from the electrical auxiliary system only. • Those which are required for the main unit shutdown.
The equipment upon which the reactor safety case depends is not connected to this system. Local distribution units are provided for each 110 V single-phase supply point, each comprising two singlephase main and standby transformers, changeover contactors, switches and distribution switchboard. These are located around the station, in the control block, etc., at suitable load centre positions. This type of distribution unit is mainly used for loads which require a single supply of high availability. Loads which require two battery-backed supplies, e.g., microprocessor systems with plant input and output, derive one supply from the unit UPS system and the other from the station UPS system via step-down transformers.
Station UPS system This comprises two UPS systems, t wo 415 V, 50 Hz, double-pole station UPS boards 57
7CX
7DY
415V ESSENTIAL SERVICES BOARDS icy •1==
■•••■•=
415V ESSENTIAL SERVICES BOARDS 8DX ■■■=
EDT'
7DX
8C y
fi 415V STN UPS7
•
•
415V LINIT UPSE
•
a-ce-a-1
a-oeci-i
415V 1PH 50Hz 1 50 (200) KVA
415V STN UPS8
o-cea-I
415V 1PH 50Hz 150 (200) KVA
46 1 1
'
• 415V UNIT UPS BOARD 7
6
'
4I5V UNIT UPS BOARD 8 -
6
6 6 6
FROM 415V STATION TURBINE SERV BD 7
•
415v STATION UPS BOARD 8
415V STATION UPS BOARD 7
6
-
-
6
6
TYPICAL 110V 50Hz C & 1 SUPPLIES LOAD CENTRE UNIT 7
1 HOUR FIRE BARRIER
UNIT STANDBY COMPUTER 7 NORMAL
110V 50Hz
BATTERY BACKED SUPPLIES
isTANDBY• • NORMAL
•
I I IL II II I I BATTERY BACKED SUPPLIES
•
a
a 7A
7B
II I I II FiG.
NORMALLY ' OPEN
UNIT MAIN COMPUTER 8
UNIT STANDBY COMPUTER 8
•
NON-BATTERY BACKED SUPPLIES
110V 50Hz
TYPICAL 110v 50Hz & I SUPPLIES LOAD CENTRE UNIT 8
B
UNiT MAIN COMPUTER 7 STANDBY
FROM 415V STATION TURBINE SERV BD 8
II
II II I I
•
NORMALLY OPEN
8B
8A
II II II II II II
1.39 Heysham 2 power station — unit and station UPS
systems
110V 501-1z
1 0v 50Hz
II II
•
I II II
NON BATTERY BACKED SUPPLIES
aqsap walsAs Iepploal3
0c)
Uninterruptable power supply (UPS) systems and a distribution network. Either of the two UPS systems is capable of supplying the following loads: • Total station load. • Standby compuier for one unit. • Standby supply to loads of one unit which require two battery-backed supplies, e.g., microprocessor system dth plant input and output. Under normal operating conditions the station load is shared as e wally as possible between the two UPS systems. Transfer of the station loads from one UPS system to another is off-load at the 110 V load centres. An interlock is provided using coded keys to prevent parallel operation of the supplies derived from the two station UPS systems. Only the following C and I station loads are connected to the station UPS Boards: • Those which are required for post-incident monitoring and recordings following loss of station AC supplies. • Those which because of stringent supply requirements would not give adequate standards of reliability if operated from the electrical auxiliary system only. • Those which are required for shutdown of any common services.
6.4 System configuration and method of operation Each UPS has the following main components (see Fig 1.34):
• Inverter failure. • Output voltage outside the set limits. • Excessive inverter overload or load inrush current. • Short-circuit on the load side. If the inverter is not in phase with the bypass supply under the above abnormal conditions, then the load is transferred automatically from the inverter to the bypass supply with a break of at least 60 ms and less than 100 ms. The load re-transfer, back to the inverter, is completed automatically without interruption in the voltage waveform when the inverter has returned to normal and maintained a stable output for approximately 5 to 10 seconds.
Static switch redundancy Means are provided within the static switch to parallel automatically the bypass power semiconductors, following a transfer from the inverter to the bypass supply, using a contactor or circuit-breaker. The control and power circuits are arranged to achieve a matching level of redundancy between the static and electromechanical portions of the static switch. In the event of the static portion failing to operate, the electromechanical portion operates to transfer the load automatically and/or manually from the inverter to the bypass supply with a voltage break of at least 60 ms and less than 100 ms. Following a transfer to the bypass supply, both static and electromechanical portions usually continue to operate to achieve maximum redundancy. Both portions are fully rated.
• Battery charger. • Battery. • Inverter. • Static switch. • Maintenance bypass switches. The charger and bypass AC supplies operate normally with identical frequency. Under adverse system conditions the supplies could operate at different frequencies. Under normal operating conditions the UPS is in service and the load is normally supplied from the im, erter. The battery charger maintains the battery on float charge. In the event of failure of the charger supply the load continues to be supplied by the battery/inverter. The load is transferred automatically from the inverter to the bypass supply without interruption in the voltage waveform under any of the following abnormal conditions, providing the inverter is synchronised in both phase and frequency to the bypass supply: • Inverter input DC voltage too low.
6.5 System considerations and components 6.5.1 Voltage regulation
With the inverter in service the voltage at the terminals of any instruments, control equipment and computers is maintained within + 6% to - 6% of nominal (steady state) voltage. This is achieved as follows for 415 V UPS systems: Regulation Inverter
+2%
415 V cable between inverter and load centre
2%
415/115 V transformer
2%
110 V cable between load centre and instrument or computer terminals
Voltage adjustment 95-105%
100% +5%
2%
59
Chapter 1
Electrical system design Output voltage and number of phases — 110 , 50 Hz single-phase output is usually used for ratings up to 10 kVA and where distribution cables are relatively short. One pole of the output is connected to earth and a 415/110 V bypass transformer is included. A 415 V, 50 Hz single-phase output is used for ratings above 10 kVA, particularly where distribution cables are long. The largest single module used today is 50 k VA. The inverter output is not earthed, but is continuously monitored with an insulation monitor. A 415 V, 50 Hz 3-phase output is used in exceptional cases where load requires 3-phases, e.g., motors. The largest rating used at present is 100 kVA.
Each transformer is provided with a facility for off-load tapchanging on the 415 V primary winding. Voltage variations of +5% in 2.5% voltage steps. The method of tapchanging is by means of bolted li nks. The nominal flux density at rated voltage and frequency and with the transformer connected on the principal tapping is specified not to exceed 1.0 tesla. The impedance voltage at rated current and frequency does not exceed 2% of the rated voltage on any tapping. The transformers are capable of operating with nonlinear loads having relative current harmonic content of up to 50%. The basic transformer parameters are given in Table 1.1.
6.5.2 UPS system loads
In order to specify a UPS system it is necessary to define the load in detail as follows: • Load profile versus time. • Loads requiring or generating harmonic (especially even) currents. • Loads requiring the circulation of a DC current. • Load steps. At existing installations, a survey of available loads is undertaken where access is possible. Measurements are taken using a two-channel digital oscilloscope with magnetic storage. The analysis of the waveforms obtained is carried out using a portable computer and a 'HARMD 1 program developed by the CEGB. A typical waveform and harmonic analysis are shown in Fig 1.40. 6.5.3 Step-down transformers
These have been developed to minimise the inrush currents and the associated voltage drops on the system, up to a rating of 16 kV. No ferro-resonance problems have been experienced with these transformers when switching them onto inverters. The transformers are of the naturally air cooled single-phase double-wound type and are suitable for operation on a nominal 415 V, 50 Hz supply derived from a single-phase inverter or from two phases of the 415 V, 3-phase, 4-wire, 50 Hz (nominal), solidly earthed system with a maximum symmetrical shortcircuit fault level of 31 MVA. The transformers comply generally with BS171, BS3535 and BEBS T2 (1966) Section 5 where applicable. The winding insulation is Class F to BS2757 and is non-hygroscopic, but the design is such that the temperature rise limits given in 13S3535, Table 2D are not exceeded for Class E materials. The use of asbestosbased materials is not permitted. A metallic screen is provided between the windings, one end of which is brought out and connected to the earth terminal of the transformer. 60
6.5.4 Standby and spares philosophy
In the event of inverter failure, automatic transfer to mains supply occurs. The quality of the mains supply is acceptable for the UPS outage time, which does not therefore justify the provision of a standby UPS system. In order to minimise time to repair, a spare set of inverter system components is kept at each station. 6.6 UPS equipment specification As part of the development work on UPS systems, detailed technical requirements and documents for purchasing UPS equipment have been written to ensure that identified problems are overcome. The following are brief details of the main technical requirements: • Battery capacity The system should be capable of maintaining specified conditions for 30 minutes following complete failure of all incoming AC supplies. • Environmental conditions The equipment should meet environmental class B3 requirements of specification CEGB-EES (1980). The ambient temperature range should be taken to be + 5 ° C to 40 ° C with air temperature not exceeding 35 ° C average in any one day and not exceeding 20 ° C average in any one year. The equipment enclosure shall provide a degree of protection to Code IP31 of BS5490. • Life of equipment All equipment should have a designed operating life of 30 years. • Reliability A high degree of reliability and availability is required and the following reliability targets are specified: UPS 3-phase output MTBF (years) Charger Inverter Static switch
10 2 10
UPS 1-phase output MTBF (years) 10 3 15
Reliability calculations are based on mean time to repair a UPS system of 48 hours.
Uninterruptable power supply (UPS) systems
DD DFESET REMOVED
-
MULTIPLY AMPLITUDES BY 1C0 % v v AND TIME VALUES BY O00020 $
-
MULTIPLY AMPLITUDES BY 2555 A V AND TIME VALUES By 0 000020 5
Harmonic Analysis using Program HAMAD
Number of points for analysis :1024 Number of cycles averaged 4 Fundamental Frequency (Hz). 50.03
Highest harmonic order 255 Voltage
Current
Total RMS 7 31A -236 - - 21V Peak value - - - - - - - - - - - - - - - - - - - - - - - - - - 319.29V - - - - - 16.01A 2_19 PeakiFtMS rano . — - - - - - - - - - - - - - - - - - - - 1.35 Maximum harmonic component rRMS) _ _ _ _ — 236_05V 6.19A DC level removed -4.28V - - - - - -0.40A Relative fundamental content - - - - - - - - - - - - - - 99.9% - - - - - 847% Relative harmonic content - - - - - - - - - - - - - - - - 3 7% - - - - - 53.2% High frequency content ,.2 k Hz) _ - - 03% - - - - - - 0.6% - - - - - - 1.727kVA Total apparent power _ Total active power - - - - - - 1.383kIN - - - - - 0 801 Power factor Cur writ CD
cn
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o
AAWWWWNWNN
o
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00
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471,
-
Voltage
DC components are excluded from all other parameters
FIG. 1.40 Typical voltage and current waveform analysis
61
Electrical system design
Chapter 1 TABLE 1.1
Step-down transformers 16
10
8
6.3
4
2.5
1.6
1
1
1
1
1
I
1
Frequency (nominal), Hz
50
50
50
50
50
50
50
Rated primary voltage, V
415
415
415
415
415
415
415
Rated secondary voltage, V
115
115
115
115
115
115
115
Voltaee ratio at no-load on the principal tapping
415/
415/ 115
415/ 115
415/ 115
415/ 115
415/ 115
415/ 115
BS posker rating, kVA Number of phases
Maximum impedance on any tapping, 'Yip Fuse links current rating at 415 V (to 13588-2, 1975, Class QI), A Maximum inrush magnetising current (peak), A
• Maintenance and repair The equipment, excluding batteries, should not require maintenance more frequently than once annually. The mean time to repair the equipment should not exceed two hours. • Transformers and inductors These should have non-hygroscopic insulation with the temperature rise necessary to give the specified life at rated output. • Power semiconductor devices The temperature rise at the device reference point (case) shall not exceed 50 ° C at the rated output. The maximum permissible temperature rise should not exceed 70 ° C under any operating conditions. For fan cooling this should apply with any single fan out of service. • Remote alarms and indications All locally indicated faults should be grouped into the following remote alarms or indications:
115 2
2
2
2
2
2
2
50
32
25
20
15
10
6
272
170
136
107
68
43
27
(c) Static switch inhibited (d) Inverter on battery.
6.7 UPS equipment performance requirements Charger output voltage The charger output voltage should be automatically maintained within ± 1 % of the voltage setting when operating under any combination of the following conditions: • Load between 0 to 100% of the rated output. • Nominal input AC voltage ± 10o. • Frequency 50 Hz +5%. • Specified environmental conditions.
(a) UPS system failure (b) Inverter in service (c) Inverter on battery (d) Battery in service (e) Static switch inhibited.
• Reliability monitoring A non-resetting counter and elapsed time indicator should be provided on UPS systems above 10 kVA rating for each of the following operating conditions: (a) Inverter in service (b) Bypass in service 62
Inverter output voltage tolerance (steady state) The output voltage should be maintained within +2% of the voltage setting when operating under any combination of the following conditions: • Load between 0 to 100 07o of the rated output over the entire inverter input voltage range. • Specified environmental conditions. • Load power factor between 0.7 lag to unity.
Output voltage adjustment The output voltage and adjustment shall be stepless over the range of ±5% of nominal voltage.
Uninterruptable power supply (UPS) systems side the limits of 50 Hz +0.1 Hz. Recent practice has been for the inverter to be free-running with a much i mproved accuracy within limits of 50 Hz +0.01 07o by means of a built-in quartz-controlled oscillator. When the bypass supply frequency returns within the tracking range, the inverter system output should be automatically re-synchronised to it, both in phase and frequency. The transition from one synchronising source to another should be performed at a rate-of-change of frequency (slew rate) not exceeding one hertz per second.
Output frequency
In order to permit operation of the static switch, the inverter should normally be synchronised, both in phase and frequency, to the bypass supply over the tracking ange of 49.5 Hz to 50.5 Hz. The bypass supply r frequency should be continuously monitored and if it goes outside the tracking range, the inverter should not follow the frequency of the bypass supply. The resulting In 's of synchronism should inhibit the static switch and initiate an alarm. While the bypass supply frequency is outside the tracking range, the inverter system frequency should preferably remain at the appropriate tracking range li mit or return to the inverter natural frequency. In the event of failure of the bypass supply, the earlier approach was to synchronise to the charger input supply. There was a risk that if the inverter was left free-running, its output frequency would drift out-
Dynamic output voltage effects
For definitions refer to IEC publication 686: 'Stabilised power supplies, AC output'. The output voltage should not exceed the limits shown in Tables 1.2, 1.3 and 1.4.
1.2
TABLE
Load effect
Load step referred to the rated output
Maximum voltage overshoot amplitude We of set value
Recovery ti me, ms
50oh to 100 07o
-15
40
5
+15
40
5
5
100 10 to
50oh
Voltage tolerance li mit We of set value
1.3
TABLE
Source voltage effect Charger input voltage steps referred to the set voltage (battery in service)
Maximum voltage overshoot amplitude We of set value
Recovery ti me, ms
Voltage tolerance li mit We of set value
(a) Loss of shortCircuit of mains
—10
40
5
(b) Mains return
+10
40
5
TABLE
1.4
Bypass supply to inverter transfer and vice versa Inverter out put voltage before transfer (battery and charger in service) 0 7o of nominal
Recovery ti me, ms
oh nominal
Maximum load voltage overshoot amplitude oh of nominal
100
110
±I0
40
100
100
+10
40
5
100
90
4-10
40
5
Bypass supply voltage
Voltage tolerance li mit % of nominal 5
63
Chapter 1
Electrical system design Output voltage waveform distortion For definition refer to IEC Publication 146 2. -
Linear loads The relative harmonic content of the output voltage should not exceed 5% when operating under any combination of the following conditions: • Load between 0 to 100% of the rated output over the entire inverter input range. • Specified environmental conditions. • Load power factor between 0.7 lag to unity. The maximum individual harmonic component should not exceed 3% of fundamental. Non-linear loads
The relative harmonic content of the output voltage should not exceed 7% with a dummy load arranged to represent the service load as closely as possible. The maximum permitted harmonic components should be in accordance with Fig 2 of IEC Publication 146 2 (1974).
After the 30 minutes' overload duty the inverter should be capable of carrying the rated output continuously. The inverter should also be capable of carrying 150% of the rated output for 5 minutes after carrying the rated output continuously. After the 5 minutes' overload duty the inverter should be capable of carrying the rated output continuously. Static switch surge capability and protection The load-to-bypass branch of the static switch should have a sufficient surge capability to withstand at least 10-times the rated output current for 5 cycles and should be protected by a fuse link. The fuse link should have a total operating I 2 t below the pre-arcing I 2 t of the bypass feeder fuse, which is rated at twice the rated load current. With assistance from the bypass supply, the UPS should be capable of clearing a solid short-circuit fault on an outgoing feeder protected by a fuse such that the interrupting time does not exceed 5 ms. Interrupting time is defined as the time during which the output voltage is below 80 07o of the instantaneous value of the corresponding portion of the previously undisturbed waveform.
-
7 DC systems Periodic output voltage modulation The periodic variation of output voltage amplitude is defined as: Vmaxpeak
VrninpeakiVnompeak
and should not exceed 11/4 including operation with the dummy non-linear load.
Rated short-circuit current capability The inverter alone (bypass supply out of service) shall be capable of clearing a fault on an outgoing feeder protected by a fuse link to BS88, 1975, Class Q1 in less than 80 ms. The fuse link rating is specified at approximately 30% of the inverter output current rating.
Overload capability The inverter should be capable of carrying 120% of the rated output for 30 minutes after carrying the rated output continuously. The output voltage should be maintained within +3% of the voltage setting when operating under any combination of the following conditions: • Over the entire inverter input voltage range. • Specified environmental conditions. • Load power factor 0.8 lag. 64
7.1 Introduction The DC supply systems are battery-backed and are designed to provide acceptably secure power supplies both with regard to continuity and quality under all normal and abnormal operating conditions. 7.2 DC system duties The following specific duties apply to the DC systems: • To supply equipment which requires a DC supply during normal conditions and which also is required to operate when AC supplies have been lost, e.g., essential instruments, control, switchgear closing and tripping, telecommunications, protection, interlocks, alarms. • To supply standby equipment required to operate only when AC supplies have been lost, e.g., emergency lighting, emergency oil pumps. • To supply the starters of starting engine-driven equipment, e.g., gas turbines or diesel generators. Under some circumstances, determined by duty, project needs and particular equipment supply requirements, selected instrumentation and telecommunications systems may be connected to the UPS systems which are described in Section 6 of this chapter.
DC systems
7.3 DC system design The systems are designed to operate from batteries for at least 30 minutes following complete failure of all incoming AC supplies. Sufficient standby capacity or standby batteries are normally provided to achieve this period during outages for repair or maintenance, or boost charging. The main reasons for limiting the period to 3) minutes are: • It is generally more cost effective to invest in improving restoration time of the essential AC supplies, rather than use larger batteries. • The 30 minute period is sufficient to shutdown a unit safely in the absence of normal AC supplies. • There are a number of DC back-up auxiliaries to the normal AC loads, e.g., turbine barring gear motors, which are required for protracted periods following the 30 minute period. The DC systems are generally provided at four voltage levels of 48, 110, 220 and 250 V DC nominal. 7.3.1
250 V DC systems
The principal duty of this system is to provide secure DC supplies for the following loads: • Emergency lighting (DC luminaires), except for remote plant buildings. • Emergency auxiliary drives, e.g., lubricating oil pumps for main turbines. • Emergency valve operation. • Fire sirens. The stations designed before 1980 used 240 V DC as a nominal voltage, this has been replaced by 250 V DC to line-up with the revised BS and IEC standard voltages. If the battery capacity selected for a given load permits, the unit systems are interconnected to cover for a battery or charger outage. A typical scheme is illustrated on Fig 1.41, used for the Littlebrook D power station, which has three 660 MW oil-fired units. The maximum battery rating applicable to the high performance Plante cells is approximately 2000 Ah at 10 hour .discharge rate and 15 ° C. Operation of more than two 2000 Ah batteries in parallel would exceed the switchgear short-circuit rating of 40 kA. A coded-key type mechanical interlock is normally provided in such cases to prevent parallel operation of more than two batteries. The Heysham 2 power station scheme is illustrated on Fig 1.42. This is an advanced gas cooled reactor station with two reactors and two 660 MW generating units.
At each voltage level the system is designed on a per unit basis. Separate systems are provided for essential loads, i.e., those upon which the reactor safety case depends on nuclear power stations. Each essential 'train' has a separate DC system, which is not interconnected to any other 'train'. Each unit has a battery and charger. A standby battery and charger are provided and can be made available to either unit when necessary. Each charger is rated to supply the total load of all DC emergency auxiliary drives of one unit, plus 25% initial spare capacity to cover for unknown loads, future load additions and the battery finishing rate of one battery (approximately 7 07o of the Ah of 10 hour discharge rate in amperes). This means that the battery can be recharged on 'float' within 10 hours following on emergency discharge duty. Each battery is rated to supply the following loads for 30 minutes: • Total load of all DC emergency auxiliary drives of one unit. • Two-thirds of total station emergency lighting load, excluding remote plant buildings, e.g., CW pumphouse. • 25 070 initial spare capacity to cover for unknown loads and future load additions. The minimum discharge voltage at the end of 30 minutes' duty is approximately 210 V at the battery terminals. This is to ensure that voltage at the equipment terminals is not less than 200 V DC (8007o of nominal). The maximum voltage drop in cables of 10 V gives sufficient scope for an economical cabling design. The 'float' charge voltage is set at 281.3 V, i.e., 2.25 V/cell for 125 lead-acid cells. 7.3.2 220 V DC systems
The switchgear within CEGB power stations uses closing mechanisms which are either solenoid driven or spring operated, the springs being motor wound. The 11 kV switchgear of one air break type, with 900 MVA make duty and 750 MVA break duty, uses solenoids rated up to 47 kW. The voltage limits of such switchgear are much tighter (+ 5%, — 15%), than those applicable to motors ( + 10%, —2007o). If the whole DC system is designed around the closing solenoids, then the battery capacity is considerably higher, typically twice the capacity without the closing solenoids. It is, therefore, generally more economical to provide dedicated batteries and chargers for switchgear closing solenoids of this rating. There is also an added advantage with respect to 'black-start' capability, i.e., the switchgear can be operated many hours or even for several days following a loss of AC supplies to the chargers. This is possible because there are no other standing loads connected to the battery. The capability 65
Chapter 1
Electrical system design
415V STATION SERVICES BOARD 3
CHARGER 2
Fic. 1.41 Littlebrook D
power station — 240 V DC station system
Pic. 1.42 Heysham 2 power station — 250 V DC system 66
CHARGER 3
DC systems
to operate switchgear for many hours following a loss of AC supplies is considered important., because it is not possible to operate it manually as can be done with the spring-closed type of switchgear. 110 V DC (nominal) is normally used for the spring charge mechanisms. To match tolerances stipulated by the switchgear standards, 105 lead-acid cells are required for the 220 V DC nomim.I voltage. A typical 220 V DC system for the non-essential part of Heysham 2 power station is illustrated on Fig 1.43. Each battery/Charger system is designed to meet the following criteria: • With the battery on 'float' up to two circuit-breakers can be closed simultaneously.
battery terminals, to ensure that voltage of the equipment terminals is not less than 96 V for switchgear and control gear and 94 V for all other equipment. The 'float' charge voltage is set at 121.5 V, i.e., 2.25 V/cell for a 54-cell battery. Separate batteries and chargers are normally provided for remote plant houses; also 120 V DC is used for gas turbine (35 MW) starting purposes. 7.3.4 48 V DC systems
The principal duty of these systems is to provide secure DC supplies for the following unit and station loads: • Sequence equipment.
• With the battery on 'float' up to 100 circuit-breakers can be closed each day; also it should not be necessary to boost charge the battery to meet this duty.
• Alarm and indication.
• Following a loss of AC supplies to the charger, the battery is capable of supplying the current of the highest solenoid rating continuously for 30 seconds. Each solenoid is normally energised for up to 500 ms and it is therefore possible to close many circuitbreakers consecutively. The minimum discharge voltage at the end of discharge duty is usually specified as 199 V at the battery terminals to ensure that voltage at the switchboard terminals is not less than 190 V. The maximum voltage drop in cables of 9 V gives sufficient margin for design purposes.
The arrangement for the Heysham 2, 48 V DC system is illustrated in Fig 1.45. To reduce cabling cost, separate systems are normally provided for unit and station equipment in locations most suited to the loads being supplied. Each charger is rated to carry the normal full interconnected switchboard load plus the recommended 'float' charge rate of both batteries. Each battery is rated to supply the total interconnected switchboard emergency load plus 25% initial spare capacity. The minimum discharge voltage at the end of 30 minutes' duty is approximately 46 V at the battery terminals and 43 V at the load terminals. The 'float' charge voltage is set at 54 V for a 24-cell battery. Separate batteries, rated for 6 or more hours, and chargers are provided for telecommunications purposes.
The 'float' charge voltage is set at 237 V, which results in the voltage per cell of 2.26 V. 7.3.3 110 V DC systems
The principal duty of these systems is to provide secure DC supplies for the following unit and station loads: • Switchgear and control gear tripping. • Switchgear closing if spring mechanisms are used.
• Remote control.
7.3.5 250 V. 220 V and 110 V DC circuit earthing
An earth leakage detection system incorporating centretapped resistors and a detection relay is normally provided in each charger. All 48 V DC systems have their positive poles earthed.
• Interlocks and protection. • Control equipment. The arrangement for Heysham 2 unit and station system is illustrated in Fig 1.44. Each charger is rated to carry the normal full interconnected switchboard load plus the recommended 'float' charge rate of both batteries. Each battery is rated to supply the total interconnected switchboard emergency load plus 25 07o initial spare capacity to cover for unknown loads and future load additions. The minimum discharge voltage at the end of 30 minutes' duty is approximately 102 V at the
7.4 DC system analysis A computer program ('GIDEAN') has been developed jointly by the CEGB and the University of Manchester Institute of Science and Technology. The program contains comprehensive models for batteries, motors, static loads, battery chargers and random momentary loads as well as reliable and efficient algorithms for the analysis of the system. Facilities include the quasisteady state calculation of the energy evolution in the battery and voltage profile of the DC network under the conditions defined by the duty cycle. The GIDEAN package provides facilities for the entry of diagrammatic and numerical data of DC net67
Electrical system design
Chapter 1
415V ESSENTIAL SERVICES BOARD 7CY (DIESEL BACKED)
415V ESSENTIAL SERVICES BOARD 8DY (DIESEL BACKED)
220V DC STATION SWITCHGEAR CLOSING BATTERY?
220V DC STATION SWITCHGEAR CLOSING BATTERY 8
105 LEAD-ACID CELLS 300 Ah,,, AT 15'C
105 LEAD-ACID CELLS 300 Ah., AT 15"C
220V DC STATION SWITCHGEAR CLOSING CHARGER 7
20A 283V
20A
FLOAT 1 HOUR FIRE BARRIER
20A 237v
220V DC STATION SWITCHGEAR CLOSING CHARGER 8
BOOST ( OFF LOAD)
237V
FLOAT
20A BOOST (OFF 283V LOAD)
220V DC STATION SWITCH GEAR CLOSING BOARD 7
220V DC STATION SWITCH GEAR CLOSING BOARD 8
TO 415V SW1TCHGEAR
TO 41 5V SWITCHGEAR
SOL TYPICAL 3.3kV SWITCHGEAR WITH SOLENOID CLOSING
FIG.
68
L43 Heysham 2 power station — 220 V DC station system
D C systems
^A
294
HI
=LOAT
I
,
1 BOOST i r cFF LOAL.
2BA
I DE
"C JET
_
I
ETA
FLOAT
12 , 5V
'Dv UN .T BA7 TERY
15 LEAD . ACID CELL1 1 4
AGON 1,.. AT I 5•C
BOOST r OFF LOAC,
DC STATION CHARGER
icv STATION BATTERY 7 54 LEAD ACID CELLS dO0An.,,AT 15-C
1
110vDCSTATFON BOARD 7
160A
1504 1
FLOAT j BOOST 110FF LOAD.
Ilia ,/ DC STATION CHARGER 8
110v STATION BATTERY g 1 , 5 1 LEAD ACID CELLS ApoAn,,,AT 15 C
FLOAT
28A r 8005; IEEE 1,OFF LOAD! ! Dc
LrNITc,HARGER
110v UNIT BATTE.v
1
LEAD ACID CELLSI 400491._ AT 75 C I
iovDC STATION BOARD
110VDC UNIT BOARD 8
NOTES , BLOCKING DIODES ARE FITTED IN 7 1 1-. E POSITIVE POLE ONLY
TYPICAL 110V OC STATION SERVICES FUSEBOAROS IEXCLUDING REMOTE PLANT NOUSESI-
Flo, 1.44 Heysham 2 power station — 110 V DC unit and station system
works; the storage, retrieval and modifications of these networks and the ability to analyse them under a variety of loadings and outage conditions. The program helps to minimise the design margins by optimising battery, charger and cable ratings. This is achieved by repeating a study with different battery, charger and cable parameters until a satisfactory DC voltage is arrived at.
The charger output voltage is automatically maintained within ± 1 % of the voltage setting when operating under any combination of the following conditions: • Load between 0 to 100 070. • ± 10% nominal input voltage. • ±5% nominal input frequency. • Between + 5 ° C and +40 ° C ambient.
7.5 Battery chargers and batteries The battery chargers
are generally of the thyristor controlled type with a 3-phase input at 415 V, 50 Hz. The typical ratings used are from 20 A to approximately 1000 A. A six-pulse rectifier configuration is generally used and a two-winding transformer is incorporated into each battery charger. The equipment is designed for an operating life of 30 years and any critical components, e.g., semiconductors and capacitors, are derated as appropriate to achieve this.
The equipment enclosure provides a degree of protection to BS5490 for code IP 31. Boost charging is carried out off-load to maintain the load voltage within acceptable limits. A coded-key type mechanical interlock is provided to prevent boost charging of the battery in service. The batteries used are generally of the high performance Plante type and the ratings are based on an ambient temperature of 15 ° C, except that batteries in remote plant houses are sometimes based on 10 ° C 69
system design
Eiectrical
4 • 5: 230ENTIAL SERVICES
eoAND 7cx
Chapter 1
4'52 ESSENTIAL SERVICES 80 701' 7C 415V
3' 5A
h I
ATL
_l
I 4s7D -",, uNrr 0,1
T
25A
B0O3 7 , OFF LOAD:I
652
325
3154
FLOAT
,42
285
/
ESSENTIAL SERVICES BOARD 8DY,
284
r 652
1. 3• SA r
FLOAT
54V
BOOST ; OFF LOAD1
415V ESSENTIAL SERVICES v8 8Cx
I
■
BOOST OFF LoADI
a$ v
BOOST OFF LOAD,
45VDC UN'' CHA.ROER 8
45vDc STATION cHARGEA 8
48203 STATION CHARGER 7
PIDAT
5,4V
T-476
48V UNIT BATTERY 7
48V STATION BATTERY l 7
480 STATION BATTERY 8
24 LEAD ACID CELLS 453 AS AT 15 C
24 LEAD ACID CELLS 433 A.AT C n.
24 LEAD ACID CELLS 450 Al, .AT 15 C
-
L
1/
Ii
440 UNIT BATTERY
8
124 LEAD ACID CELLS ; 1
400 All
AT 15 C
•
_41
2
"A 48 vCC UNIT BOARD 7
80 DC STATION BOARD
7
•
•
V
0
0— 0
0
•
II
TYPICAL 48vCC UNIT 7 FuSEROARD
II II
11
0 =
eLocxING DODES ARE
FITTED IN THE NEGATIVE POLE ONLY
2 ALL 415V ESSENTIAL BOARDS ARE DIESEL •BACKED
•
=0 .
II
48VDC UNIT BOARD 5
NOTES I
•
u
•
48V0C STATION BOARD 8
I HOUR FIRE OARRIER
II
•
1 1 11
TYPICAL 48vDC STATION SERVICES FLISEBOARDS I EXCLUDING REMOTE PLANT HOUSES)
II II II
. 11 11 11
324 MAX
TYPICAL 4861DC UNITE PuSEBOARD
Fic. 1.45 Heysham 2 power station — 48 V DC system
ambient temperature. Batteries are located in dedicated rooms as close as possible to the associated charger/ distribution switchboard rooms. All battery rooms are provided with suitable thermostatically controlled heating to maintain the design temperature. Adequate ventilation is provided in all battery rooms to keep the concentration of hydrogen gas within safe limits. Details of the equipment are given in Chapter 9.
Electrical system monitoring and Ateriocking schemes 3.1
Introduction
Fhe safety of personnel when using or maintaining
.lectrical equipment and systems is at all times covered )y rules and administrative procedures, in particular '0
the CEGB Safety Rules. These rules and procedures are fully considered in the design of the electrical plant and systems. in addition, interlocking, monitoring and indication facilities are included in designs to achieve the following: (a) Minimise the probability of human error faults occurring. This is an aid to operators and maintenance personnel in carrying out their duties to meet the operating and maintenance rules and procedures. (b) Safeguard plant and equipment where it is considered necessary to provide interlocking for this purpose. This section describes the interlocking, monitoring and indication facilities installed at 11 kV, 3.3 kV and 415 V to meet items (a) and (b). These facilities are divided into two categories:
Electrical system monitoring and interlocking schemes •
Operational interlocking, fault level monitoring and indication equipment.
• Ensure that only those circuit-breakers provided with synchronising equipment are used to connect different sources of generation.
• Maintenance interlocking equipment. 8.2 Operational interlocking, monitoring and indications In deciding he type of facility required, the following guidelines ate used: • In systems where on-load parallel operation of a number of circuits is the normal method of operation, and where the switchgear is not overstressed ‘‘hen a number of circuits are in parallel, then no interlocks should be provided. Administrative rules and procedures are adequate to cover this method of operation. • In systems where on-load parallel operation of circuits would cause the maximum specified fault level li mits of the switchgear to be exceeded, operational interlocking or monitoring and indication equipment can be installed to prevent the limits from being exceeded. Both relay logic and computer logic schemes have been used. The choice is largely based on the complexity of the scheme, as the electrical relay logic scheme becomes difficult to design when there are a large number of possible interconnections to consider. In such a case, the number of relays and quantity of cabling between cubicles of switchgear becomes prohibitive and verification of the logic is difficult to achieve. In addition, changes are extremely difficult to incorporate. An alternative is to use a computer-based scheme which continually monitors circuit-breaker states, and calculates if the next circuit to close will cause an unacceptable operating condition. A computer-based scheme can be either indicative only, or indicative and preventive; and can be programmed to model the whole electrical system, providing full flexibility in switching Operations. Relay schemes use circuit-breaker auxiliary contacts and relay contacts, with any additional relays mounted or interconnections made, in purpose built boxes mourned adjacent to the switchboard concerned. Examples of interlocking schemes used are shown in Figs 1.46, 1.47 and 1.48. The example shown in Fig 1.46 illustrates some of the electrical operational schemes used. They are provided to: • Prevent the two transformer sources being connected together at 3.3 kV, as this would cause fault level
li mits to be exceeded.
• Allow the diesel generator to be connected to either transformer when testing the diesel generators.
Figure 1.47 shows a scheme to allow only 3 out of 4 interlocked circuit-breakers to be closed as shown in Fig 1.46. Figure 1.48 shows how to achieve the cabled interconnector electrical interlock and the transformer electrical interlock, as illustrated in Fig 1.46. 8.3 Relay systems An operational interlocking scheme is required to: • Prevent switching activities which could cause the design fault levels of the systems switchgear to be exceeded. • Ensure the correct sequence of circuit-breaker operations for achieving check synchronising. Interlocking is normally accomplished by directly wiring together various combinations of switchgear auxiliary contacts into the operating circuits of other switchgear. Thus a particular item of switchgear may only be operated if the auxiliary contacts of other switches are in such a configuration as to allow completion of the operating circuit of the switch in question. The switchgear contacts used in the interlocking schemes are generally wired into an interlock box, containing repeat relays and the interlocking logic, the box being mounted close to the switchboard to be interlocked. Connections from the switchgear to the interlocking box are made via marshalling cubicles, with all the cables being multicore cables having 2.5 mm 2 conductors. Interlock schemes should be designed to be 'fail safe', i.e., the relays have to operate and positively drive the interlocks to allow the switchgear to be operated. The equipment is operated from a 110 V DC battery source and able to operate within the DC systems specified variations and fluctuations of supply voltage level. Supply supervision relays are provided to monitor all fuses, and a clean pair of contacts from this relay is provided per suite of cubicles to initiate a remote alarm. Local indication identifying the failed fuse is provided, arranged to be visible without opening the cubicle. 8.3.1 Switchgear auxiliary contacts
The open or closed state of each item of switchgear is determined from an arrangement of switchgear auxiliary contacts. An index of these auxiliary contacts used in interlocking schemes is shown on Fig 1.49. This drawing shows the latest computer aided drafting symbols, alongside the old symbols used until recently, for each type of contact and defines their operating philosophy. 71
Chapter 1
Electrical system design
iikv
tkV
lc al
BA
TRANsFoRmER1 8
A S
I CB1
3 3kV Ims
c)
DIESEL GENERATOR 1
CB21
IC 31 \
■••16•■•■••••1■■■.
4.
8 IC841
■•••
TRANSFORMER 2
5
l
■momm 3 3kV
"N.
KEY A
Circuit breaker fitted with automatic synchronising facilities Circuit breaker filled with manual synchronising facilities
3
Indicates electrical Interlocks between a circuit-breaker group. The figure in the left hand 4 corner denotes the number of breakers in that group permitted to be closed at any one time. The figure in the right hand corner denotes the total 'number of circuit-breakers in the group
y\c,
Cabled Interconnector Electrical Interlock. The circuit breaker without synchronising facilities cannot be closed if the remote breaker with check synchronising is closed first. See Fig. 1.50
Transformer Electrical Interlock. The H.V. circuit breaker may only be closed if the L.V. circuit
A T breaker is open. See Fig. 1.50 E
FIG. 1.46 Example system to illustrate the logic of electrical operational interlocking schemes
8.3.2 Application of interlock schemes
Definition of interlock types The various interlocks that are used to manage different interlocking schemes are depicted by unique symbols which can be added to system diagrams. These different interlock symbols are shown in Fig 1.50. General interlocking schemes Certain interlocking requirements on different plant systems have resulted in common interlock schemes being developed. These common interlock schemes have been refined and incorporated into an index of basic schemes, and are shown in Fig 1.51. When developing a scheme for a particular application, two or more of these general interlocking schemes may be combined to produce an overall scheme that will provide the necessary interlock requirements for the correct and safe operation of the plant. Variations in the cabling requirements can occur for these same basic interlocks, 72
depending upon the number of marshalling cubicles involved and also the distances between boards. These variations are covered by loop diagrams which support the circuit diagrams. Where synchronising interlocking facilities are required on a circuit-breaker already involved in a separate interlocking scheme, the synchronising interlocks are incorporated into the more complex overall interlocking scheme, where they then form part of that scheme. For more details of synchronising, see Chapter 12. Considering some of the more typical configurations shown in Fig 1.51 in detail: • Transformers and interconnectors As a general rule, transformers are introduced into the system by first closing the HV circuit-breaker, thus energising both the RV and LV windings, and then closing the LV circuit-breaker after synchronising checks have been carried out. To ensure that this procedure is followed in the correct sequence, an operational interlock is fitted which prevents the HV circuitbreaker from closing if the LV circuit-breaker is
Electrical system monitoring and interlocking schemes
SOURCE
SOURCE 2
1
1 , 0V DC SUPPLY
SW.TC:HBO4 PD
SECTION A
SECTION C
SECTION B
CB1 LOC CB2 POE - -a
(re-1.."•-wip I
CB2 LOC CB 3 POS
- 0--*
(4■
1%.-ms
CR3 LOG CB4 POS
aCB 4 LOC :RC I
a OBI
1 R-1
a
4P-1
2R ,
a 3R.I
IR2
IRC 2 a----
CB2
4R.2 PLANT PROTECT:ON < INTERLOCKS
IRC 3 CB3
a iRC.4 SUPPLY a FAIL ALARM
1
\ CB4
a
FIG. 1.47 Circuit diagram showing '3 out of 4' interlocked circuit-breakers
already closed. Check synchronising interlock facilities are fitted to the LV circuit-breaker which prevents it closing if unacceptable voltage mismatch or phase differences exist. Interconnectors, especially cable interconnectors, when not in service are usually left energised, from one end only, so as to monitor the integrity of the circuit continually. Bringing the interconnector into service, however, must always be accomplished via the circuit-breaker fitted with the check synchronising facilities. To ensure that this procedure is always followed, operational electrical interlocks are fitted which prevent the circuit-breaker without synchronising facilities being closed if the circuit-breaker with the check synchronising is already closed. Check synchronising interlock facilities operate as described above. The circuit and loop diagrams for the transformer or interconnector arrangement are shown in Figs 1.48 and 1.52 respectively.
When the above interlock scheme has to operate between local and remote circuit-breakers of such separation that direct wiring between the plant protection interlocks would cause excessive volt drop in the circuit-breakers control circuits, then circuitbreaker repeat relays are used. • One out of two
Operational electrical interlocks are fitted to the circuit-breakers of both feeder circuits connected to the board. These interlocks prevent both feeder circuit-breakers being closed at the same time, which would otherwise result in unacceptable paralleling of the supplies. Either of the two feeders may be selected for duty and closed onto the board, but having accomplished this the interlocks then prevent the remaining feeder circuit-breaker being closed. No synchronising facilities are required as the above interlock prevents the two supplies being connected together. This scheme is shown in Figs 1 .53 and 1.54..
• Two out of three
This interlock scheme is designed to prevent the paralleling of supplies without in73
Chapter 1
Electrical system design
gear in a correct and predetermined sequence with all out-of-sequence operations inhibited. If sequence interlocks are specified on the transformer and interconnector circuits, their application must be developed and incorporated into the operational interlocking scheme as shown in Fig 1.57. It should be noted that the sequence interlock does not inhibit the operation of circuit-breaker No 2 in any way, and it is not therefore an alternative to an operational interlock.
11kV. 3 3kV AND 415V BOARD 2
BOARD
(.1)
(1)
2 y , ]
INTERCONNECTOR ..--■•■••••■■ HV
r•-•
8.4 Computer-based systems \
,
1 3 301 TRANSFORI,IER
TRANSFORMER
LV LOC DIRECTLY CONNECTED INTERLOCKS
— Ca CA OE LV
OPPOSITE END C8 2 OR CB HV PLANT PROTECTiON INTERLOCKS
INTERLOCKS VIA RELAY WHERE ROUTE LENGTH BETWEEN SWITCHBOARDS INTRODUCES UNACCEPTABLE VOLT DROP
P05
OP
J1
CB 05 LV
1I}
PR A 1 ..?
--C1=-0 _ ARA J2 –
0
--
I
W-'--OPPOSITE END CB OA CB NV PLANT PROTECTION
"– rt
2
--INTERLOCKS
Circuit diagram showing cabled interconnector and transformer electrical interlock
FIG. 1.48
hibiting the operational flexibility of the system. Operational interlocks are fitted to the circuit-breakers of both feeder circuits and on the bus section circuitbreaker of the board. The system may be operated with both feeders closed onto their respective halves of the board (as long as the bus section circuitbreaker is open), or if maintenance is to be carried out on one of the feeder circuits, both halves of the board can be coupled together via the bus section circuit-breaker and the board fed from the remaining feeder. No synchronising facilities are required as the interlock prevents any paralleling of supplies. This scheme is shown in Figs 1.55 and 1.56. • Sequence operational interlocks
Sequence interlocks, if required, are to ensure the closure of switch-
74
As mentioned above, an alternative and more flexible arrangement for system monitoring is to utilise a computer-based scheme. The most recent of these installed by the CEGB has been at Heysham 2. From the description of the electrical auxiliaries system in Section 3.2 of this chapter, it will be apparent that a relay logic scheme for achieving interlocking could have proved to be cumbersome and possibly restrictive in the connections available to the operators. The decision was therefore made to develop and install a computer-based monitoring system. The block diagram for a computer-based fault level monitoring and indication equipment which has been installed is shown in Fig 1.58. This equipment does not prevent any circuit-breaker from closing. The equipment advises the operator when it is unsafe to close a circuit-breaker by an indication at the point of switchgear control. Dual computer systems operating in a main and standby mode are provided for main unit failure or routine maintenance. The equipment is designed for mean time between failure (MTBF) of 10 years. The computer system allows changes to be made to the number of circuitbreakers being monitored and the plant data used in the computer model without the need to modify the software. The fault level calculation and graphical display software for the system is based on the UMIST IPSA package (see Chapter 2) with modifications to enable the software to run in real-time, providing colour displays acceptable for use in a central control room (CCR) and switchgear safety status information (LED states). As the software has been specified to be flexible and allow circuits and switchboards to be added arid removed, it follows that it can be used on future or existing power stations. A monitor in the CCR can display the connections and switchgear for any of the switchboards included in the system. The display identifies any switchgear which cannot be closed safely at any instant in time and gives the potential increase in fault level if this were to be done. Each switchgear control switch in the CCR is also provided with a red LED, which is illuminated if it is unsafe to close the circuit. A times
Electrical system monitoring and interlocking schemes
Old Symbol
(
-
Component description
New Symbol
k
Withdrawable metelcled switch9ear
)1
7
Circuit-breaker general symbol
Y (0, -)
Circuit-breaker with HBC tripping use
i
I
T
Ott-load Disconnector
Y Fuses: (LH) general symbol (RH) with supply side shown by thick line
II
I
I/ _ —
Relay coil
— —0
1
OH
Relay Contact: normally closed in de-energised stale Relay Contact: normally open in de-energised state
—0 0—
Fic. 1.49 Index of component symbols, old and new
record is also provided for each switchgear change of state, for confirmation of operation and post-incident analysis. The information provided by the computer will be used as an advisory aid by the operator. Although a computerised interlocking system has been installed at the Drax coal-fired power station, it was decided not to provide full interlocking at the Heysham 2 nuclear power station. This decision was taken so that the operators would not be inhibited from reestablishing vital electrical supplies under controlled emergency conditions to ensure reactor safety. The natural progression of the computer-based systems is towards full interlocking schemes and elec-
trical auxiliaries system remote control. The CEGB are investigating several options to this end which, in the case of the remote control feature, would supersede the need for the full mimic panel in the CCR with discrepancy switch control used at present.
8.5 Maintenance interlocking equipment Maintenance interlocking is concerned essentially with personnel safety while maintenance is being performed on electrical equipment. Plant damage must also be considered, but is less likely due to the plant being nonoperational during maintenance. 75
Electrical system design
Indicates electrical interlocks between a circuitbreaker group.
The figure in the LH corner denotes the total number of circuit-breakers in the group permitted to be closed at any one time The figure in the RH corner denotes the total number of breakers in the group.
Li. El ,i-
5 I Or, / 4
V
./1
Indicates electrical interlocks between a circuitbreaker group.
The figure in the LH corner denotes that a maximum of 3 out of the 5 circuit-breakers with this symbol may be closed at any one time. The exception to this would be when a selected circuit-breaker is open. i.e.. the bus section, under this condition the interlock allows the remaining 4 breakers to be closed.
Transformer electrical interlock.
This circuit-breaker, (HV) can only be closed if the remote circuit-breaker, (LV) is open_
Interconnector electrical interlock.
This circuit-breaker can only be closed if the remote circuit-breaker is open.
Chapter 1
isolated and in the case of HV, earthed. To assist the operators in implementing the Safety Rules it is normal to apply a discrete coded-key procedure designed for each system. This procedure only allows access to the next stage, after the previous operation has released a coded-key which in turn has to satisfy the next set of criteria. Following the system ensures that all the necessary isolation and earthing has been achieved in accordance with the Safety Rules prior to allowing man access to plant. The choice of a maintenance interlocking scheme is largely dependent on the perceived maintenance requirement and complexity of the plant concerned. The mechanical interlocking will be based on codedkeys and key exchange boxes. The following type of mechanical interlock key facilities are available to be used: Symbol Type
Synchronising.
Circuit-breaker fitted with synchronising facilities, Can only be closed if supplies are synchronised.
A
E/
D
A
Proof of earthing key • A key free only when the circuitbreaker or earthing switch or switching device where applicable is closed in either the busbar or circuit side earthing location. Removal of the key shall lock the circuit-breaker or earthing switch or switching device in the earthing location. (Key type 'Al' — circuit earthing, Type 'AT — busbar earthing.)
Automatic synchrbnising
Circuit-breaker fitted with auto-synchronising facilities. Once this function has been selected the breaker will auto close when supplies are synchronised
Transtormer electrical interlock.
y
Function
This circuit-breaker (LV) can only be closed if the remote circuit breaker (HV) is closed, and supplies are synchronised.
interconnector electrical interlock.
This circuit-breaker can only be closed if the remote circuit breaker is closed, and supplies are synchronised.
Note: Although 3.3 kV circuitbreakers are provided with circuit earthing and, where specified, busbar earthing facilities; 3.3 kV fused switching devices are provided with facilities for circuit earthing only.
FIG. 1.50 Definition of symbols for types of interlock
Although the CEGB Safety Rules do not require mechanical interlocking, it is current policy to provide a system of coded-key interlocks to assist the operator in applying the Safety Rule requirements. The interlocking system is based on the following sequence:
• Alternatively, a key made available by an Authorised Person after the satisfactory application of portable earths.
• Isolation at all points of supply. • Proof of isolation. • Earthing all items of equipment. • Proof of earthing. • Issue of Permit for Work'. The objective is to allow safe access to electrical equipment for maintenance purposes. Access is controlled by a rigid set of Safety Rules specifically drawn up and controlled by the CEGB, under a formal Permit for Work' system. These ensure that access is denied until all electrical apparatus has been switched off, 76
B
Permissive close key A key which, when inserted, permits the circuit-breaker or switching device to be closed and is free only when the circuit-breaker or switching device is open. Attempted removal of the key when the circuitbreaker or switching device is closed shall not cause tripping of the circuit-breaker or switching device. Alternatively for a disconnector, a
Electrical system monitoring and interlocking schemes
,
.I.I.
7..... HV
HV
, ,
i
ill
X
•
,
I 1
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1
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el \
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l
\:11(''
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‘ SwITCHBOARD SECTION B
...---7—
SECTION C
i
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11.v 3 3kv 8 415v
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\
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1
.....L 111,V 3 3kV
SCJRCE ,
SOURC E 2
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!I kV 3 3kV
A
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Y
II
-
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--
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SOURCE?
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i
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rl Ir "
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Y
1
S OURCE 3
I
7
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SOURCE I
t
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I
,,,,„ „k,„&4,5,
"•L' 3 3,2 1415V
2
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SOURCE 3
N
:\I
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a 415V
SOURCE 1
SOURCE 2
SOURCE 2
V
3
(5)
I
SWIT H. ROB
1
ri't \ \ \I
Al i
SWITCHBOARD A;
Y
I NTERCONNECTOR
SOURCE 3
i
,
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ri
k
2
S
8 41SV
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SOURCE 2
— \I I
)
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1 ‘
="
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LV
BOARD?
80ARD 1
rt — /
SOURCE i
■onLme. 1 /kV 3 3 ■0., a 4'5V
I 11,V 3 3kv 8 415V SOURCES1
•
5E: - CN A
Lv
1 . 1 BOARD 3 _1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - J z IkV 3 3IN d. 415 'V
SOURCE? —
i
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to s \.),
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re/7 ' 4 k
v\
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BOARD ?
1 skV 3 3101 6
4 4v
)
Y
, d_ ) BOARD 3
Y
FIG. 1.51 Index of basic operational interlock schemes 77
Electrical system design
Chapter 1
MARSHALLING CUBICLE
CB 1 OR CO LV
CB2 OR CB HV
MARSHALL/NG I TERM INTERLOCKING CUBICLE . No. RELAY PANEL
I TERM I
201
101
f
POS LOC
DIRECTLY CONNECTED INTERLOCKS
PLANT PROTECTION INTERLOCKS
POS
Ito vOLT DC
. No . DISTRIBUTION BOARD
LOC
202
203 INTERLOCKS VIA RELAY WHERE ROUTE LENGTH BETWEEN SWITCHBOARDS INTRODUCES UNACCEPTABLE VOLT DROP
PLANT PROTECTION INTERLOCKS
1 02
FLA — 1 RRA 1
204 0
SMR I
SUPPLY
FAIL ALARM
206
Fit,. 1.52 Loop diagram of operational interlocks for transformer or interconnector
SOURCE 2
SOURCE
r
Symbol Type
2
(cont'd)
cei POS riNN—Gma
Function key which, when inserted, permits the disconnector to be closed and is free only in the 'disconnected' position. It shall not be possible to close the disconnector with the key removed. Attempted removal of the key when the disconnector is closed shall have no effect. (Key type `13D'.)
CBI LOC
PLANT PROTECTION TNTERLOCKS CB2
C82 POS C62 LOC
PLANT PROTECTION INTERLOCKS CBI
FIG. 1.53 1 out of 2 circuit-breaker operational
interlock circuit diagram 78
A
Permissive earthing key A key which, when inserted, permits the circuit-breaker or earthing switch or switching device where applicable, to be closed in either the busbar or circuit side earthing location and is free only when the circuit-breaker or earthing switch or switching device is open. Attempted removal of the key when the circuit-breaker or earthing switch or switching device is closed shall not cause tripping of the
Electrical system monitoring and interlocking schemes
CIRCUIT BREAKER 2
CIRCUIT BREAKER
LOCAL MARSHALLING
CUBICLE
CB POS CB LOC
PLANT PROTECTION INTERLOCKS
CB POS CB LOC
0
PLANT PROTECTION INTERLOCKS
1.54 1 out of 2 circuit-breaker operational interlock loop diagram
SOURCE 1
110V DC SUPPLY
SOURCE 2
2
3
-
CB1 POS ODCB1 LOC
CBI
CB2
_Hr
PLANT PROTECTION INTERLOCKS
C53
SMR
1
SUPPLY 10 FAIL ALARM
FIG. 1.55 2 out of 3 circuit-breaker operational interlock circuit diagram 79
Chapter 1
Electrical system design
olgoulT BREAKER 1 CE 200
MARSHALLING CUBICLE
CIRCUIT BREAKER 3
CARCUIT BREAKER 2
TERM No
r
TERM No
INTERLOCK/NG RELAY PANEL
203
1 01
204
102
CIV DC DISTRIBUTION BOARD
,
L OC
!
CE
2,i27
2
OS LOC-1
I R-2
3R
,
205
IRC-1
206 PLANT PROTECTION I INTERLOCKS ,PPL
(
TEl
'
JRC-2
209 4 210 213
PRI
-a-
4
1
1FIC 3
214 4
201 SUPPLY 0-4 FAIL 202 ALARM 4 215 21 ,5
0_
1210 8
SPARE TERMINALS
a 219
FIG. 1.56 2 out of 3 circuit-breaker operational interlock loop diagram
Symbol Type
A
(cont'd)
Function circuit-breaker or earthing switch or switching device. (Key type 'Cl' — circuit earthing, type `C2' busbar earthing.) Although 3.3 kV circuit-breakers are provided with circuit earthing and, where specified, busbar earthing facilities; 3.3 kV switching devices are provided with facilities for circuit earthing only. Proof of isolation key
• A key free only when the cir-
cuit breaker or switching device is removed from the service location. It shall not be possible to insert the circuit-breaker or switching device into the service location with the key removed, but it shall be possible to insert -
80
Symbol Type
(coned)
Function and operate the circuit-breaker or switching device in either the earthing or isolated locations and to insert and operate the earthing switch where applicable in the earthing locations. Release of a key type 'D1' must not inhibit subsequent circuit earthing and, similarly, release of a key type 'D2' must not inhibit subsequent bus bar earthing. • Alternatively, a key free only when the fixed circuit-breaker, disconnector or earth switch is fully open. Removal of the key shall lock the equipment in the fully open position. • Alternatively, a key made available by the Charge Engineer after
Electrical system monitoring and interlocking schemes Function
Symbol Type ,
BOARO 2
1kV33kV5 415V
H (coned)
A INTERCONNEC TOR
key is trapped until the original position or mode of operation is reselected. A key that is normally in a key exchange box and is released only when all the permission keys have been inserted. This indicates, on a drawing, the normal location of the key when the circuit is in service.
CH MARSHALLING CUBICLE
L. CB ' OA CB',"
•
!
CB 2 OR CE! NV
:
.
POS or•—■.0„,•••—■ •
n,ANT RPOTECTION 'NTERLCCKS •
:
LOC
7
X
•
Transformer and interconnector sequence interlock scheme — circuit diagram
D
(coned)
LjJ
IL7
E
H
Subscript Y, a key associated with the yellow phase of the equipment for use in local key exchange schemes.
Function
satisfactory mechanical isolation of the main turbine-generator or diesel generator. Disconnector position key
Subscript X, a released key in the secure possession of an Authorised Person to enable the Permit for Work to be issued. Subscript R, a key associated with the red phase of the equipment for use in local key exchange schemes.
FIG. I .57
Symbol Type
Subscript CH, a key normally in the possession of an Authorised Person released only after satisfactory completion of the specified activity.
A,
Subscript B, a key associated with the blue phase of the equipment for use in local key exchange systems.
A key which, when inserted, permits the disconnector to be closed or disconnected and is free in both 'closed' and 'disconnected' positions. Removal of the key shall lock the disconneetor in the 'closed' position. Removal of the key in the 'disconnected' position shall not prevent complete withdrawal of the carriage nor access for maintenance.
The Isolation Earthing Key Exchange Boxes operate by receiving one key from each specified item of equipment and then releasing one key for each specified item of equipment to be earthed. Certain items of equipment will require local key exchange boxes as each phase of the equipment has an individual interlock key system.
Operation facility key
8.5.2 Scheme application
A key which, when inserted, permits the desired position or mode of operation to be selected. The
A typical example of applying a coded-key interlocking
8.5.1 Key exchange boxes
scheme is illustrated on Fig 1.59 and the associated procedure is as follows. 81
Chapter 1
Electrical system design
STATION DATA CENTRE
CENTRAL CO
' SYSTEM 1 DISPLAY ! MONITOR 1; KEYBOARD
LOGGING PRINTER 1 'ALARMS EVENTS ,
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FIG. 1.58 Block diagram for computer-based fault level monitoring and indication equipment
3.3 kV Chlorination plant board 7(8) The following system permits work on all circuits on
the above switchboard except the circuit spouts of transformers and interconnectors: (a) Isolate all points of supply from which the busbars can be made alive, releasing keys as detailed below: •
•
•
Type DI key from 3.3 kV Interconnector to Chlorination Plant Board 8(7), the key being obtained from the remote circuit-breaker in the isolated position. Type D1 key from 3.3/0.415 kV Chlorination Plant Transformer 7(8), the key being obtained from the 415 V circuit-breaker in the isolated position. Type DI key from 11/3.3 kV Chlorination Plant Transformer 7(8), the key being obtained from the 11 kV circuit-breaker in the isolated position.
(b) All voltage transformer isolation must be carried out and checked (no interlocks are provided). 82
(c) A key exchange box will be provided to accept the above three keys. When all keys are inserted two Type C2 keys will be released. (d) The two Type C2 keys will then be inserted into any two of the circuit-breakers through which it is possible to feed (including backfeed) the switchboard. The busbars are then earthed through these two circuit-breakers at two circuit positions. (e) When each circuit-breaker is closed on to earth, a Type A2 key will be released. (f) The Type A2 keys will be held by an Authorised Person and locked away to enable 'Permits for Work' to be issued. (g) To allow access to the busbar spouts of one of the circuit-breakers used for earthing the busbars, the Authorised Person will release one of the Type A2 keys, permitting the earth to be removed and the withdrawable portion removed. It will not be possible to maintain both circuitbreakers used for earthing the busbars simultaneously. The Authorised Person will have to retain
Electrical system monitoring and interlocking schemes
11 kV STATION BOARD 7B (88)
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FIG. 1.59 Typical coded-key maintenance interlocking scheme
at least one of the Type A2 keys to satisfy the Safety Rule earthing requirements. (h) Reinstatement of supplies will be established in the reverse order. Note:
It has been assumed that the Chlorination
Plant Electrolysers are 'dead end feeders' in the above
procedure. 8.6 Other safety interlocking During normal operation it is imperative that all
equipment which contains live metal must be designed such that access is denied at all times whilst the equipment is energised. Typical examples of this are switchgear cubicles where internal access is not possible when the isolator is 'on', which is done by ensuring that in this position the door cannot be opened. Although these requirements are written in the equipment specification, there are several ways to achieve the objective. The choice must be one of a balanced design, preventing defeat from the unintentional act but at the same time not building in complications which makes normal operation more difficult.
83
CHAPTER 2
Electrical system analysis 1 Principles of electrical system analysis 1.1 Introduction 1.2 System design assessments 1.3 Analysis program developments 1.4 Analysis techniques 1.4,1 Reliability evaluation 1.4.2 Power system performance analysis 1.5 Quality assurance of analysis programs 2 Reliability evaluation of power systems 2.1 Introduction 2.2 Quantitative reliability evaluation 2.2.1 Choice of numerical indices 2.2.2 Scope of reliability evaluation assessments 2.3 Computer programs for reliability evaluation 2.3.1 Batch program — RELAPSE 2.3.2 Interactive program — GRASP (Version 11 2.3.3 Interactive program — GRASP (Version 21 2.4 Data requirements 2.4.1 Active failure rate 2.4.2 Passive failure rate 2.4.3 Total failure rate 2.4.4 Average repair time 2.4.5 Switching time 2.4.6 Maintenance rate 2.4.7 Maintenance time 2.4.8 Stuck probability 2.4.9 Time limit of a limited energy source 2.4.10 Common mode failure rate 2.5 Techniques employed 2.5.1 Graphical representation of the station electrical System
1 Principles of electrical system analysis
1.1 Introduction The assessment and validation of electrical power systems in terms of their predicted performance and comparative levels of reliability and availability are essential tasks in the early design phases for all major projects. This is particularly important in respect of those aspects of the design and performance necessary for ensuring the safe and satisfactory integration of various types of power station into the CEGB grid supply system. Broadly, the primary functional design objectives of electrical system analysis are to: • Ensure that the designs for plant and system net84
2.5.2 Component and branch numbering 2.5.3 Branch definition 2.5.4 Criteria of failure 2.5.5 Analysis control procedures 2.5.6 Deduction of minimal paths 2.5.7 Deduction of minimal cut sets 2.5,8 Types of failure/restoration event 2.5.9 Switching effects of component active failure 2.5.10 Markov state-space models 2.5.11 Evaluation techniques (busbar indices) 2.5.12 Evaluation techniques (system indices) 2.5.13 Presentation of results 2.6 Quality assurance 2.7 Typical applications 2.7.1 Example of the calculation and use of busbar indices 2.7.2 Example of the calculation and use of system indices 3 Power system performance analysis 3.1 Load flow analysis 3.1.1 Introduction 3.1.2 Program construction [4,5] 3.1.3 Use of programs 3.2 Fault level analysis 3.2.1 Introduction 3.2.2 Program construction 3.2.3 Use of programs 3.3 Stability analysis 3.3.1 Introduction 3.3.2 Analytical and programming considerations 3.3.3 Use of programs 3.4 Future developments of electrical analysis programs 4 References
works comply with specified operating performance and safety criteria. • Evaluate the comparative performance and cost effectiveness of alternative plant designs and system configurations. • Determine and optimise plant and system parameters for technical performance specification purposes. • Provide the electrical characteristics necessary for the design of electrical protection systems. • Define system and plant constraints for operational and maintenance procedural purposes. System and plant parameters are Currently fully represented by mathematical models in the design process
Principles of electrical system analysis nd, with the evolution of digital computer aided design facilities over the past fifteen years, the scope and detailed representation of Dower system simulation studies has increased significantly in comparison with earlier analysis techniques. Also, with the increasing involvement of computers, there are continuing possibilities for the development and enhancement of the computer programs described later in this chapter. a
1 1 System design assessments The design and operation of power systems require comprehensive analysis in order to evaluate the performance under normal and abnormal conditions of operation, whilst recognising the defined system performance and safety criteria discussed in Chapter 1. In this regard, both power system performance and reliability evaluation analysis play equally important roles in achieving a high standard of overall power system integrity and ensuring the optimal utilisation of capital investment in power station plant and systems. System integrity is particularly important for nuclear power stations, for which nuclear safety and district hazard assessments have to be made in support of the application for an operating licence. The design assessments must necessarily involve the reliability evaluation and power system performance analysis of the interface connections between the grid system and the power station, together with the station electrical systems which provide electrical power to the boiler/reactor, turbine-generator auxiliaries and station services plant. The station electrical systems comprise many supply systems of the radial type, including transformers, switchgear, motors, gas turbine and diesel generators, cables and connections. 1.3 Analysis program developments Power system analysis involves some very complex numerical processes which, together with the entry of system data and the extraction of essential results, constitute a very substantial workload on the design engineer in making assessments of system performance. It is important, therefore, that aspects of computing organisation such as operating procedures and commands are removed, as far as practicable, from the design engineer's tasks to enable him to concentrate on the quality of the system design and performance. To this end, separate suites of batch mode and interactive computer programs have been specifically developed to incorporate the following 'user-friendly' features: • System networks are drawn on the computer terminal screens in diagrammatic form, thereby providing a familiar framework for the engineer to identify the correctness of the system for analysis purposes.
• Data tables are generated automatically from the diagram information for each of the plant components and system connections. • Self-explanatory help and option menus are displayed on the screen and, where necessary, specific error messages or warnings are displayed. • Display options allow key results to be displayed either directly on the network diagram or in tabular and graphical form. The programs' user-friendly' operating procedures are particularly enhanced by the extensive application of computer graphics for the input of system and plant data, results output and control functions. Typical examples of system network diagrammatic and graphical output displays that are capable of being copied by means of a hard copy unit directly from the computer terminal screen are shown in Figs 2.1 and 2.2. Experience in the collaborative development of computer aided system analysis programs, has demonstrated that the final quality is particularly influenced by how well the design concepts, needs objectives, and organisational and responsibility arrangements are jointly established at the inception of the development project. Particular emphasis is therefore placed on the design concepts and objectives being formulated on a sound technical basis, while ensuring that associated important design functions, such as program structure, controls, mathematical models, calculation routines, data-base management, etc., are clearly defined. To assist further in the definition and understanding of the overall program logic, flow charts (typically as depicted in Fig 2.3) are produced at the commencement of each development project. The chart displays all the activities which need to be considered in the development of a new program and provides the starting point for the computer software program designer. The further development of computer aided analysis programs is an ongoing task in order to keep abreast with the rapid technological advances being made in plant and system designs, e.g., the introduction of modern electronic speed and voltage controllers for governors and automatic voltage regulators (AVRs), thyristor drive controllers, vacuum switches, fast operating electronic protection equipment, etc.
1.4 Analysis techniques Prior to the development of the computer analysis facilities described in the previous section, hand calculations formed the main method of analytical solution; these were supported, whenever possible, by AC and DC analyser facilities for system load flows, fault levels and transient fault performance. Such analysis techniques were inherently time consuming and permitted only simplified representations 85
Electrical system analysis
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of electrical auxiliary systems and associated plant. They involved network reduction techniques, with many design performance approximations and assumptions; sensitivity and iterative studies, invoking permissible system and plant design tolerances, were necessarily of an extremely constrained nature. With present day computer programs and computing facilities, the analysis techniques are vastly more comprehensive, efficient and precise than older methods. Batch mode and interactive analysis programs enable the predictive performance of station electrical system designs to be optimised on an iterative basis, with much more detail and a higher degree of accuracy than previously, in an extremely short time. Batch mode computing systems are capable of analysing the performance of more than one power system at a time and are primarily suitable for processing the extensive amounts of information and results associated with the dynamic transient analysis of large systems. Such studies may, for example, involve a computational time of about 10 minutes for a single 86
4 0.7 .
short term transient condition of 5 seconds, but they can of course be submitted for analysis during computer off-peak periods at night times and weekends. Interactive on-line computing, by comparison, allows the design engineer to interface with, and directly control, the analysis process from a computer terminal in respect of the network representation, type of study required, system parameters, corrective actions and output result displays. While interactive computing is highly user orientated and consequently more time demanding at the terminal for the design engineer, it is much faster than batch mode analysis systems in the overall turn round time of producing results, especially for steady state power system studies. The availability of separate suites of batch mode and interactive computer programs, when coupled with their respective databases, enables a series of specific power system performance or reliability evaluation analysis studies to be undertaken in a uniform manner, by varying the system parameters and the type of study. As a consequence of the ability to control the type
Principles of electrical system analysis
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GENERATOR SPEED (PU ON 50 Hz - 1000 r(min) PONY MOTOR SPEED (PU ON 50 Hz H$ OR LS) "-••••••
PONY MOTOR CURRENT (PU ON RATING)
FIG. 2.2 Gas circulator pony motor speed change study
of study and sequence of studies from within a suite of programs, the efficiency and speed of response in producing assessments of large complex systems has increased significantly. For example, having entered all the system and plant data, the design engineer is able to produce the results of a power system steady state analysis or reliability evaluation study within a matter of seconds for a complete power station electrical system, including the grid interface connections. It is also a relatively simple exercise to undertake sensitivity studies to identify the system components and parameters having a critical impact on the overall system performance. One should not, however, overlook the considerable design effort and time that is involved in setting up the system networks and the collation, checking and entry of the system plant and connection data for modelling and simulating complete station electrical systems fully. This may amount to something in excess of eight man weeks for a large power system. 1.4.1 Reliability evaluation
A reliability evaluation study forms the normal starting point for comparing the effectiveness of alternative
interface connection arrangements between the grid system, the turbine-generator units and the associated station electrical supply systems. The extent of the system evaluation undertaken, using interactive computing programs, incorporates the following analysis features: • Failure rates. • Outage durations. • Outage times. • Common mode failures. • Limited energy sources. • Time dependent reliability. The basic techniques required to analyse and evaluate the reliability of the systems include the simulation of realistic failure events, restoration procedures, switching actions, maintenance events and operational constraints. For multiple turbine-generator power stations with identical unit and station systems, it is more efficient to divide the systems into subsystems. This technique, as explained in detail later, is not only efficient and 87
Chapter 2
Electrical system analysis
SYSTEM DRAWING AND MODIFYING ROUTINE
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precise but reduces the design engineering effort involved in the preparation and input of system component data.
• Transient fault stability performance of systems and motors.
1.4.2 Power system performance analysis
• Transient recovery voltage levels.
Batch mode and interactive computing programs are used to assess the performance of integrated and isolated power systems in respect of:
• Controller modelling of AVRs, governors and prime movers.
• Load flows, voltage regulation and transformer tapchanger optimisation. • Short-circuit (symmetrical and asymmetrical) fault levels. • Dynamic motor starting performance. 88
• Fast transient switching of systems and motors.
• Power system protection co-ordination of relays and fuses. Power system performance analysis is largely based on load flow, short-circuit and transient stability studies. The analysis, using nominal plant parameters, commences with the calculation of the steady state power
Reliability evaluation of power systems flows, voltage distributions and short-circuit fault levels throughout the system during no load, minimum load, start-UP and CMR sequence loading (block loading) conditions of the turbine-generator unit operation. During this stage of the analysis, transformer tap changer positions are adjusted, as appropriate, to achieve the optimum system voltage profiles for these conditions of operation. Dynamic motor starting and system transient fault .tability performance evaluation studies are also intro& during this process for the optimisation of system and plant parameters. Further stcady state, dynamic response and transient fault stability sensitivity analyses are then performed, selectively invoking permissible plant manufacturing tolerances, defined system operating ranges of voltage and frequency, and credible system and plant outage operating conditions. Calculation of system dynamic responses uses a step-by-step approach, starting from a specified balanced steady state operating condition produced by a load flow study. Analysis programs contain a number of models for the representation of synchronous machines and induction motors; they automatically select the most suitable model, according to the amount of data provided by the user in terms of the machine model parameters. The most detailed models of a synchronous machine include the transient and sub-transient and saturation function parameters, together with the excitation and speed governor controller model block diagram transfer function elements. Other loads are represented as fixed impedances, while the transformers, transmission and cable connections are represented by their equivalent circuit parameters. Inclusion of the effects of instantaneous voltage and frequency deviations into the calculations, produces a more realistic assessment of system behaviour under transient conditions. The widely used diesel or gasturbine generator supported essential supply systems in nuclear power stations are examples of such operating situations and a special purpose transient analysis program has been developed for assessing their dynamic performance. This program recalculates the plant and s,stern parameters throughout the transient variations of instantaneous voltage and frequency, thereby enabling the systems and plant to be designed and operated closer to their limits, coupled with the ability to define the settings of the associated protective devices more accurately. Detailed descriptions of power system reliability ev aluation and performance analysis are given in the following Sections 2 and 3 respectively. These descriptions are comprehensively illustrated by authentic computer printouts generated by the software programs under discussion, i.e., they have not been subjected to any form of artistic licence.
1.5 Quality assurance of analysis programs Particular emphasis is placed on achieving the highest
possible standard of quality by instituting rigorous verification and validation testing disciplines from the inception of a program up to the stage when it is formally released in a production status version. Test systems, representative of the wide spectrum of the electrical systems encountered within power stations, are used for the quality assurance of all program versions and enhancements. Each development and production version of a program is identified with a unique identification reference, which is displayed on the VDU during analysis and is subsequently printed automatically on the system input, network diagrams, graphical and output data sheets. At an early period in the development process, an appropriate level of verification and validation testing is initiated and formally recorded with respect to program source codes, models, calculations and control routines. Verification activities are progressively increased during the development, involving extensive testing and comparison of the source codes with the mathematical models by the specialist software programmer. The verification and validation tasks are the responsibility of the design engineer, who undertakes a comprehensive comparison of the mathematical models and program results with manual calculations, field measurements of plant and system performance tests and, whenever applicable, with earlier versions of the program and alternative validated analysis programs. The widespread utilisation of a program by many design engineers for the analysis of various types of integrated and isolated power systems is an additional i mportant contribution to the verification and validation process. Notwithstanding the procedures and disciplines outlined it is recognised that the verification, validation and modification of computer programs may continue for many years following their formal introduction at a production status level. Rigid quality control disciplines must continue to be exercised in this regard in accordance with the procedures outlined.
2 Reliability evaluation of power systems
2.1 Introduction The reliability of larger turbine-generator units (500 MW and above) in modern power stations is assuming increasing significance in terms of system security and the economics of supply, since they are used in the main to meet the base load requirements of the grid system. It follows that all the supporting auxiliary plant and systems within each station must have a similar high degree of reliability, in order to minimise the impact of their failure on the overall reliability of the main units. 89
Electrical system analysis
Chapter 2
The Station Electrical System (SES) is an example of one such internal system: it can be considered to have three constituent parts:
culated and used as a measure of the 'goodness' of a SES. The following are typical examples of suitable indices:
• The MAIN system, the principal function of which is to distribute a sufficient supply of electrical power of the required quality to all the drives and auxiliary plant associated with the boilers/reactors and turbine-generators. Failure of all or even part of this system could have a direct impact on the availability of a main generator, causing either the total loss or reduction of output from the generator to the grid system.
FR
Failure Rate, the expected average number of failures in a specified period
MTBF
The Mean Time Between Failures
MTTR
The Mean Time To Repair
AOD
The Average Outage Duration or average down time
OT or OD The total Outage Time or total Outage Downtime in a specified period
• The GUARANTEED system which supplies power of guaranteed quality to computers, instruments, etc., necessary for the operational control and monitoring of the power station. Sometimes this is referred to as the No-break system and is required to continue to function during large system disturbances, unit start, shutdown, etc.
ER
• The ESSENTIAL system which comprises standby generators and associated electrical connections and drives (some of which are common with the MAIN system). This is sometimes called the Short-break system and is generally used (with or without the standby generators) to supply power to all those auxiliaries necessary for the safe operation and posttrip cooling requirements of nuclear stations and for black starting of fossil-fired stations.
The interactive computer programs developed specifically for the quantitative reliability evaluation of power station electrical systems (described in Section 2.3 of this chapter) calculate, list and/or display the reliability indices. The following indices have been selected as the most useful and appropriate in the iterative process of system design:
It is important, therefore, that a reliability assessment of all three parts of the SES is performed during, and as an integral part of, the design process and should cover all the system operating configurations and station running modes. Reliability assessment, as such, is not a new requirement. Engineers have always striven to design systems that will continue to operate in a safe and reliable manner. In the past, this reliability has generally been achieved by drawing on the experience of design and operational staff and using purely engineering and qualitative criteria. Quantitative assessment, due mainly to the sheer tedium of the calculations involved, tended to be limited to the evaluation of relatively small systems (comprised of few components). 2.2 Quantitative reliability evaluation It is clear that a quantitative evaluation of the SES
reliability is of considerable help in decision making during the design phases of any power station project. It consists of the calculation of a set of numerical indices which provides a measure of the 'goodness' of the system and can be used during the design phase to compare one system with another.
LOG
The total Loss Of Generation in a specified period due to system unreliability
LOR
The total Loss Of Revenue in a specified
period due to system unreliability The Encounter Rate for operation in various derated states (see (b) below).
(a) For a particular load point or node of a SES: FR
Expected average number of failures of supply to the load point in a year (failures/year)
AOD Average outage duration or downtime — average time for which no supply is available at the load point (hours) AOT Total annual outage time — total time in a year when no supply is available at the load point — (hours/year). (b) For the SES as a whole: ER
Expected frequency of operation of the power station or main generator unit in various derated states in a year (occasions/ year)
AD
Average duration of operation in each of the derated states (hours)
AOT Total time of operation in each of the derated states in a year (hours/year) LOG Expected loss of generation in a year due to the unreliability of the SES (MWh/year). 2.2.2 Scope of reliability evaluation assessments
2.2.1 Choice of numerical indices
There are many reliability indices that could be cal90
The availability of very powerful modern mainframe computers led to the development of efficient computer
Reliability evaluation of power systems programs containing algorithms which facilitate the probabilistic assessment of the reliability of very large electrical systems (systems containing a very large number of components). With such computing facilities, the system design engineer is provided with a very powerful design aid. Such assessments facilitate the following design activities: • The corn larison of alternative designs of SES with regard to the reliability of supply to corresponding nodes or 1 aad point busbars in each system to which it is proposed to connect certain critical plant. • Indication of how a system may fail, assessing the consequences of such failures and providing sufficient information to enable the quality of a system to be related to agreed reliability standards or targets. Where the agreed standards/targets are not achieved, sensitivity calculations can be undertaken during the design phase to enable the design engineer to decide what improvements to the system should be made and whether the capital cost of such improvements (if any) is acceptable. • Quantitative assessments of the loss of generation (in MWh/year) resulting from the unreliability of the SES. The unreliability of the SES can thus be expressed in financial terms by applying the current figure for the marginal cost of replacement generation (running alternative plant which is more expensive in terms of cost per unit output). • Checking that, for a nuclear station, the proposals for the provision of local (on-site) standby generation and the methods of connecting this to the SES, ensures that the contribution of the SES to the total probability of a degraded core does not exceed the agreed design target. • Inclusion of the effects of common mode failure (CM F) in an assessment of the SES (if suitable data is available) when the proposed physical disposition of the various components is known. Alternatively (even without such CMF data), the sensitivity of the system reliability indices to the CMF of certain groups or sets of system components can be examined. 2.3 Computer programs for reliability evaluation The CEGB has undertaken, over many years, the de‘,.elopment of computer analysis programs specifically for power system reliability evaluation, by adapting and enhancing any techniques that can be applied to the numerical evaluation of reliability and incorporating these techniques in computer programs for use in system design.
2.3.1 Batch program
—
RELAPSE
During the first development project, the techniques, which are described in more detail in Section 2.5 of this chapter, were incorporated into a computer program designed to run in batch mode but capable of analysing only small systems (containing up to about 15 load point busbars or nodes). This first batch program (called RELAPSE — Reliability Evaluation of Electrical Systems) was not very 'user friendly'. The data preparation stage was extremely laborious, requiring the completion of numerous data sheets from which sets of punched cards were produced. It was necessary for these to be checked thoroughly for accuracy and arranged in the correct order in a deck suitable for computer input via a card reader. The turnaround for each study took anything up to three days. 2.3.2 interactive program
—
GRASP (Version 1)
The main objective of the next development project was an interactive version of the RELAPSE program, suitable for running under a time sharing system (TSO) from a remote graphics terminal. Briefly, this work entailed the improvement of the RELAPSE algorithms to make them more efficient and the development of new algorithms for the graphics drawing routines, data entry and editing, file storing and retrieval, etc., all of which were designed to make the program more 'user friendly'. With this interactive program (called GRASP — Graphic/interactive Reliability of Auxiliary Systems of Power stations), once having set up the system to be evaluated and entered the appropriate data, full 'on-the-spot' control of the analysis study is available to the user. Not only can the basic assessment of the system be undertaken but, due to the flexibility built into the program, a whole range of sensitivity studies can very easily and quickly be undertaken by changing the system topology and/or data and re-running the study to obtain instant results. Various options are built into the program, which can be exercised by the user to control both the precision and objectives of each study. Part of this development also included increasing the array dimensions within the program to enable much larger systems (containing up to about 50 nodes) to be evaluated and inserting full protection against malfunctioning of the program, together with appropriate error message displays. The interactive drawing routines developed for the GRASP program are very similar (as perceived by the user) to those of the Interactive Power Systems A nalysis (IPSA) programs described elsewhere in this chapter. 2.3.3 Interactive program
—
GRASP (Version 2)
During the development and use of GRASP1, it was recognised that the scope and efficiency of re91
Electrical system analysis liability assessments could be significantly enhanced by the introduction of subsystem concepts, common mode failure evaluation and limited energy sources representation. Subsystem concepts' Due to the fact that, for a reliability evaluation, the graphical input of a system had to be performed on a component-by-component basis, it became apparent that this was now the most tedious part of the work required of the user of the interactive program. Recognising that, in general, the SES for a typical power station could be broken down into four or five broadly similar subsystems, the next development project included (amongst other things) the provision of an improved graphics drawing system. The system developed is known as the Subsystem Drawing Routine. With this system, implemented in the GRASP2 interactive computer program, it is only necessary to input the system and data for, say, the SES associated with one generator unit of a four-unit station and then use the computer to reproduce this three times and store as separate subsystems. It is possible, of course, to retrieve each of the individual subsystems and make minor changes in the normal way. For a complete representation and subsequent analysis of the complete SES for a four-unit station, it is then necessary to draw the remainder of the SES, i.e., the Station System, separately as the fifth subsystem and use the Interconnector Drawing Facility to interconnect all five subsystems, as necessary. The result of this development is to reduce to about one-third, the effort required of the user to input a large system, compared with that previously required with GRASP I. Common mode failure evaluation The batch computer program RELAPSE and the first interactive program GRASP I only included overlapping independent failure events and maintenance events. It is a requirement in laying out a power station that segregation is maintained between the components of each power system, and those of all other systems. This is not easily achievable due to space limitations, and can be very costly. The close proximity of components, such as can occur within cable tunnels, switchrooms, etc., suggests that certain groups of components are susceptible to common mode failure. To add more precision to the assessment of the reliability of a SES, this development included the extension of the algorithms, drawing routines and models and equations within the GRASP2 interactive program, so that events involving the common mode failure of certain user specified groups/sets of components could be included in the evaluation. 92
Chapter 2 Limited energy sources
Although the techniques developed and incorporated within the RELAPSE and GRASP I programs included restoration modes which made use of local standby generators, no account was taken of the fact that such standby plant may only be capable of supplying the required system power for a limited time. Under circumstances where, for example, a time limit was imposed by the size of on-site fuel storage tanks, the assessment of the SES reliability would not be correct, if the restoration mode involved the use of the standby plant. New algorithms were therefore developed for the GRASP2 program to take account of this time limit and thereby permit a more realistic representation and assessment of the real system. 2.4 Data requirements The methods of reliability evaluation used within the GRASP interactive computer programs require a selection of the following component reliability data, according to the purpose and wider objectives of each study. 2.4.1 Active failure rate
The average number of times per year that a component fails actively. A component active failure is defined as one which results in the operation of protective devices to isolate the entire zone around the failed component automatically, e.g., a short-circuit. 2.4.2 Passive failure rate
The average number of times per year (failures/year) that a component fails passively. A component passive failure is defined as one which does not result in the operation of any protective device but would nevertheless cause loss of supply to the busbar under consideration, e.g., an open-circuit or the false opening of a circuit-breaker. 2.4.3 Total failure rate
The average of the total number of failures per year (for which records are available) that require the removal of the component from service for repair due to either of its failure modes (active and passive). 2.4.4 Average repair time
The average time (hours/failure) taken to repair all failures (active and passive), for each component. 2.4.5 Switching time
Following a component active failure, the average ti me (hours) taken to isolate manually the failed com-
Reliability evaluation of power systems ponent and restore all possible healthy components to service. 2.4.6 Maintenance rate
The a% era2e number of occasions per year (outages/ ear) that a component is taken out of service for pro entke or scheduled maintenance. 2.4.7 Mai itenance time
The average duration (hours/outage) of all scheduled maintenance outages for each component. 2.4.8 Stuck probability
The probability (expressed as a decimal fraction) that
a circuit-breaker or switch will fail to open/close when called upon to operate. Also, the probability that a standby generator or limited energy source will fail to start on demand. 2.4.9 Time limit of a limited energy source
The average time (hours) for which a limited energy source can supply the energy requirements of the system. A limited energy source (LES) is a standby energy source which can only supply the system energy re-
quirements for a limited period. 2.4.10 Common mode failure rate
The average number of times per year (failures/year)
that the particular group or set of components fail in common mode. A common mode failure (CMF) is defined as the si multaneous failure of several components due to a single external cause. The multiple failure effects must not be consequences of each other. 2.5 Techniques employed The techniques employed within the interactive computer programs are described in this section. The various stages in the process of evaluating a SES are
described in roughly chronological order.
An explanation is given of the objectives of each stage and the methods employed for their achievement. It is not intended to provide here, detailed instruction in the use of the computer program. For this, the reader is referred to the User's Manual for the GR ASP2 computer program [1]. 2.5.1 Graphical representation of the station electrical system
evaluation of a SES is therefore to input the system to the computer using interactive graphic techniques. The system is drawn on the VDU display, component by component. The symbols used are those normally recognised by engineers as representing the components of a SES, for example, two interlocking circles to represent a transformer; a filled in rectangle to represent a busbar, etc. The drawing routine has been deliberately developed to allow full flexibility and freedom to construct and display the system in the most presentable manner (naturally, it has to be electrically correct to represent the exact system that is to be evaluated). Full control can be exercised in respect of the order in which the components are drawn and their position on the screen. Mnemonic codes are used to call for the appropriate symbol to be drawn at the required position on the screen (selected with cross-hair cursors). A list of these mnemonic codes is shown in Fig 2.4. Whilst the full rules to be followed for the graphical input of a system are provided (together with step by step illustrations) in the program Users Manual, it is appropriate at this point to list the salient features of the drawing routine. • The system is drawn component by component, branch by branch. • Mistakes in drawing an easily be rectified by use of the 'Delete' and/or 'Forget' commands. • A facility exists to enable the presentation of the complete diagram to be improved at any stage of the drawing process by moving components around on the screen (the associated connections linking the component to the adjacent components are automatically re-routed). • Further changes to a completed diagram can be made by adding complete branches or by deleting components or branches. If an individual component is deleted, a connection is automatically drawn to link its preceding and succeeding components within the branch. • A system, once drawn, can be permanently stored, together with its associated component reliability data for subsequent retrieval and use. • A system can be re-centred on the screen and/or re-scaled to allow additions to the diagram at any time. On subsequent storing of the system, the new scale factor or centre co-ordinates are also stored. • Branches are designated as either unidirectional or bidirectional, according to whether power flow through the branch can be in one direction only or in either direction as an acceptable operating condition.
An engineer traditionally likes to represent any engi-
2.5.2 Component and branch numbering
neering task in which he is engaged in diagrammatic form. The first stage in the quantitative reliability
As mentioned earlier, the interactive computer program (GRASP2) is based largely on digital (number 93
Chapter 2
Electrical system analysis
CODE
SYMBOL
COMPONENT
S
BUSBAR
U
INTERCONNECTION
G
GENERATOR
1
I
MOTOR
T
2W - TRANSFORMER
C
CONNECTION
B
NORMALLY CLOSED CIRCUIT BREAKER
W
SOURCE
P
NORMALLY OPEN CIRCUIT BREAKER
R
REACTOR
A
AUTOTRANSFORMER
0
CABLE
Z
ISOLATOR
L
LIMITED ENERGY SOURCE
3
3W - TRANSFORMER
)
(( I t...._ ..._
FIG. 2.4 List of component codes and symbols
manipulation) techniques. There are many internal number systems used in the program which are not displayed to the user. There are, however, two important number systems, namely component and branch numbering, which are displayed and provide the user interface. They are both automatically applied to the system and can (at the user's option) be included in the graphic display on the VD U. Component numbering
A component numbering system is used to identify every component of the SES uniquely. As well as providing a user interface, the component numbering system provides the interface with the component reliability database in which is stored the reliability data to be used in the evaluation. Since numbering of all components by the user would be a very tedious task (there can be upwards of 300 components in a single system), it has been 94
arranged that the numbering is automatically carried out by the program. The component numbers can be displayed at any stage of the drawing process, the numbering sequence being continually updated as drawing proceeds. The individual component number consists of a prefix which, in general, is the mnemonic code used to draw the component (see Fig 2.4), followed by a number representing the order in which components of that particular type were drawn. Figure 2.5 is an example of a small system as it would appear on the VDU, complete with its component and branch numbering. Branch numbering
In addition to providing a user interface (branch numbers can be displayed in the same way as component numbers), the branch numbering system plays a part in improving the efficiency of the program. Certain types of component are defined within the program as being 'branch terminators', as follows:
Reliability evaluation of power systems
NETWORK DRAWING AND MODIFYING ROUTINE
FIG. 2.5 Example of a computer printout of a small SES system complete with component codes and branch numbering
Branch definition
• Source — a start component.
2.5.3
• Generator — a start component.
A branch is a group of components electrically connected in series between any pair of terminating components, as listed in the previous section. Branches which are terminated at one end with either a source, a generator, or an LES symbol are referred to as source branches. Branches which are terminated at one end with an induction motor symbol are referred to as load branches. A unidirectional branch is one through which, as an acceptable operating condition, the flow of power is normally in one direction only. By definition, a source branch is unidirectional FROM the source and a load branch is unidirectional TO the load. A bidirectional branch is one through which the flow of power can be in either direction as an acceptable system operating condition. With a knowledge of the system and its normal and abnormal operating configurations, the engineer defines
• Limited energy source (LES) — a start component. • Busbar or node — a start or finish component. • Three-winding transformer — a start or finish component. • Induction motor — a finish component. According to the network topology, components electrically positioned between two terminating components are automatically assigned branch numbers. The branch numbers are shown in parentheses in Fig 2.5. Branches are numbered upwards from (1). The lower order numbers in the sequence are assigned to the unidirectional branches (in the order they were drawn), followed by the bidirectional branches (in the order they were drawn). A definition of unidirectional and bidirectional branches is given in the following section.
95
Electrical system analysis each branch of the system as uni or bidirectional as part of the system drawing routine. On the graphic display unidirectional branches are distinguished by a small arrow just before the branch termination (finish) component. Bidirectional branches have no special symbolic notation. In Fig 2.5, branches (1) and (2), are unidirectional. 2,5.4 Criteria of failure In performing a reliability analysis of a SES in terms of its load point busbar indices, the criterion of failure is regarded as the complete loss of supply to each load point being evaluated. A Failure event for a particular load point busbar, is any event that leads to loss of continuity between the busbar and any source of supply. The failure events are therefore identified from the Minimal Cut Sets (MCS) associated with the Minimal Paths between the load point and all sources of supply (sources, generators or LESs): • A Path is a set of components that connects any input node to the load point being considered. • A Minimal Path is a path in which no node or branch is included more than once. • A Cut Set is a set of components that, when failed, causes loss of supply to the load point under consideration. • A Minimal Cut Set is a cut set that causes failure of supply to the load point but, when any one component of the set has not failed, does not cause failure of supply to the load point. 2.5.5 Analysis control procedures In performing a quantitative reliability analysis of a SES the engineer, in addition to ensuring that the SES has been correctly modelled from a topological viewpoint, has to ensure that the subsequent reliability calculations reflect any operational constraints and will be performed with the required precision. This optional control of the analysis is achieved through engineer/program interaction in the form of a series of questions put to the engineer by the program at the point where calculation of load point (nodal) or system indices is about to commence. A basic set of control questions is displayed in respect of both load point and system indices calculation. These, together with the default (most commonly used) answers, are illustrated in Fig 2.6. For calculation of the system indices, it is necessary for the engineer, from his knowledge of the system, to provide supplementary data prior to commencement of the calculation stage. These data relate to the continuous maximum rating of the turbine-generator unit or station (according to the basis on which it is desired to calculate the system indices) and the impact that the loss of supply to each load point busbar in 96
Chapter 2 the SES would have on the output of the associated generator unit or station. 2.5.6 Deduction of minimal paths The initial stage of the topological part of the analysis consists of the deduction of the minimal paths associated with each load point to be included in the evaluation. Digital techniques are used to deduce all the minimal paths between each load point being analysed and all sources of supply to the SES. All paths are deduced and, when displayed on the VDU screen or listed in a printed output, the normally closed (NC) and normally open (NO) paths are listed separately. Each minimal path is listed first in terms of node and secondly in terms of branch numbers, commencing at the load point being considered and working back towards the source or input node. It should be noted that the designation (with due regard to any system operational constraints) of certain branches as unidirectional leads to greater efficiency of the path deduction process. Paths containing branches where the direction of power flow would be opposite to that specified by the engineer during the system drawing stages are ignored or excluded. This, in turn, leads to reduced data storage requirements within the program. Smaller arrays are set up and manipulated, which result in enhanced execution time. Alternatively, the designation of some branches as unidirectional can be regarded as a means of allowing larger SESs to be evaluated within the existing set program array dimensions. As an illustration of the path deduction process, Fig 2.7 shows the list of minimal paths for the small system of Fig 2.5. It should be noted that all loop paths, and also paths involving the flow of power in the reverse direction through a unidirectional branch, have been eliminated. By answering Y (yes) to the sixth control parameter question (Fig 2.6), it is possible to specify sets of incompatible components and thereby preclude the deduction of unrealistic or impractical paths. 2.5.7 Deduction of minimal cut sets The next stage of the topological part of the analysis is the deduction of the minimal cut sets for each load point under consideration. A full treatment of the minimal cut set theory as applied in the reliability assessment of general electrical networks is provided in [2]. A minimal cut set of order 'n' is a set consisting of n components. As the order increases, its significance with regard to its contribution to the load point or system reliability indices decreases. Using cut set analysis techniques, it is possible to deduce minimal cut sets of any order but the algorithm developed for, and implemented in, the GRASP computer programs
Reliability evaluation of power systems
EXECUTION CONTROL PARAMETERS:-
DO N/0 PATHS FAIL WHEN REQUIRED TO OPERATE?, MAXIMUM NUMBER OF OVERLAPPING OUTAGES DO YOU WANT TO CONSIDER STUCK BREAKERS? ARE THE FAILURE EVENTS OF N/O PATHS OF FIRST ORDER? THE MAXIMUM PERMITTED NUMBER OF N/D BREAKERS IN A GIVEN PATH DOES TH: SYSTEM CONTAIN INCOMPATIBLE COMPONENTS? DO YOU WANT THE PROGRAM TO DEDUCE THE BREAKERS WHICH TRIP DURING A/F?
2 2
TO EDIT A PARAMETER ,LOCATE THE CURSORS AT THE ANSWER AND PRESS THE SPACE BAR
OPTIONS:1-REDISPLAY 2-PREPOTTE0 ANSWERS 3-HELP 9-EXECUTE 5-RETURN
CRASP-2
TOE, 13 OEC 1388
1 534:17
FIG. 2.6 VDU display of a basic set of control questions
only considers cut sets up to and including third order. For a particular study, the order of cut sets included, and hence the precision to which the reliability indices are calculated, is controlled by entering a 1, 2, or 3 against the control parameter 'Maximum Number of Overlapping Outages' in Fig 2.6. The algorithm for the deduction of minimal cut sets from the (NC) minimal paths for each load point works as follows: Step I
Deduce the first order cut sets by considering every branch one at a time, checking whether it belongs to every (NC) path. If it does, then it is a first order cut set.
Step 2
Expand the branches into their constituent components to determine all the first order cut sets in terms of components.
Step 3
Eliminate any duplicated first order cut sets.
Step 4
Deduce the second order cut sets by considering all combinations of two branches. If any of these combinations is found to break all minimal paths, the combination is a second order cut set.
Step 5
Expand each branch of each combination that is found to be a second order cut set into its constituent components to determine the second order cut sets in terms of pairs of components.
Step 6
Eliminate any duplicated second order cut sets.
Step 7
Deduce the third order cut sets in the same way, by repeating Steps 4 to 6 and considering all combinations of three branches.
Figure 2.8 lists the cut sets up to second order deduced for the system of Fig 2.5. There is only one first order 97
Chapter 2
Electrical system analysis
LOAD CONNECTED TO NODE NUMBER S 3 /SUBSYSTEM NO. 1
•
LIST OF SYSTEM PATHS
NUMBER OF PATHS • 4 PATm 2
3 4 1ONTImuE
9
COmPOmENT mu.SERS 2 53/1 01 , 1 52 , 1 02 , 1 L G 5 53/1 54/1 52/1 42/1 13/1 51/1 W1/1 2 3 PATHS mOPMALLY 7 0 13/1 S4 , 1 52/1 42/1
4 4 OPEN 4
v,H
7R40P-2
PG,
2.7 Minimal paths for the system illustrated in Fig 2.5
cut set (the load point busbar itself) and 60 second order cut sets. Figure 2.9 lists the cut sets up to third order for the same system. It can now be seen that, in addition to the 61 first and second order cut sets, there are 60 third order cut sets. Whilst the contribution of an individual cut set of order greater than one to the overall reliability indices may be insignificant, the total effect of all higher order cut sets cannot be ignored. It can be shown that for power station electrical systems in general, a very large number of higher order cut sets are deduced and second order cut sets contribute significantly to the overall indices. The simulation of realistic failure events during the calculation stage requires that failure events where recovery is from standby or alternative sources, via (NO) paths, are separately identified. 2.5.8 Types of failure/restoration event
The following realistic failure/restoration events are included in the evaluation as appropriate to the system topology and the operational effects to be considered: (a) Overlapping forced outages due to component (independent and common mode) failures involving repair or replacement. (b) Forced outages due to component active failure (independent and common modes) and their switching effects on healthy components. The primary protection zones can either be automatically de98
T411, 02 JOH 1980
tected by an algorithm within the program or be specified by the engineer, using his knowledge of
the actual system protection arrangements. (c) Forced outages due to component (independent and common mode) failures overlapping a maintenance outage. (d) Forced outages due to component active failures (independent and common mode) overlapping the malfunction of primary protection equipment (stuck breakers). The back-up protection zones are detected automatically by the program. The GRASP program has been developed to simulate five basic types of failure/restoration event. They are categorised according to the component failure mode and the procedure adopted for the restoration of supply
to the load point being evaluated: TYPE 1 A cut set where all components of the set are outaged or failed in passive mode, e.g., for maintenance or repair. Supply can only be restored to the load point being evaluated by returning to service at least one of the components of the cut set. TYPE 2
A cut set with the same component failure
mode as for TYPE 1, but with at least one normally open path available which can be used to restore supply to the load point being evaluated.
Reliability evaluation of power systems
•
LOAD CONNECTED TO NODE 10118E1 8 3 /SUBSYSTEM NO. 1
•
•
•
LIST OF CUTS NuABER OF CUTS • 61 CUT
1 2 4 5
7 O LO
ii 12
13 14
10 1 0 17 1111 1 9 20 21 22 23 24 25 26 27 28 29
30 Si 32 33 84
35
96 $7 SO 99 40 41
42 43
COMPONENT NumSERS $3/1 Si/t $2/1 S111 N2/1 S1/1 03/1 Slel T2/I
61/1 414/1 51/1 $4/1 S1/1 B9/1 SI/1 12/1 S1/1 B10/1 S1/1 01/1 $2/1 17/1
$2/1 02/1 02/1 BB/1 12/1 M1/$ $2/1 11/1 $.2/7 Till 52/1 82/1 02/1 07/1. 02/4 02/1 142/1. 88/1 142/1 N1/1 142/1 1111/1 42/1 T1/1 142/1 02/1 07/1 sail 87/1 T2/1 111 7/1 14/1 02/1 8S/1 02/1 T2/1 02/i B4/i 88/1 83/1 Be,' 72./i 18/1. 34/I B7/I 54/1 02/1 34/1 88/I $4/1 17/I 119/1 87/1 12/1 87/1 840/1 02/1 19/1 02/1 02/1 02/1 1318/1
7ONTINUElY/N GRASP-2
44 45 40 47 41 49 08
58 59 60 01 BY CLOSING A
17/1 04/1 02/1 01/1 18/1 01/1 83/1 W1/1 T211 01/1 04/1 01/1 83/1 81/1 83/1 T1/1 83/1 132/1 12/1 11/1 12/1 TII1 T2/1 82/1 84/1 Bi/1 1411 T1/1 84/1 12/1 NORMALLY OPEN PATH
CUT
. PATHS
THAT MAY 88 CLOSED
18 30
4 4 4 4
52
ea 84
55 58
57
THAT
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ELIMINATES
39
48
41
42 43 44
45 46
02 JUN 1918
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CUTS
THU,
4 4
4 4 4 4
GRASP-2
THU,
02 JUN 1900
1
FIG. 2.8 Minimal cut sets for the system illustrated in Fig 2.5
99
Electrical system analysis
Chapter 2
•
•
LOAO CONNECTED TO NODE NUMBER S 3 /SUBSYSTEM NO. 1
•
•
LIST OF CUTS NumBER OF CUTS •121 CUT
2 3 4 5
COMPONENT NUMBERS
03/1
szet
S1/1 S1/1 7/1 SI /1 83/1 S1/I 72/1
1 9 20 21 22 23 24 75 76 77 TB 19
SL/I 84/1 S1/1 $4/1 S1/1 89/1 51/1 R2/1 Sl/L 810/1 01/1 01/1 32/1 87/1 02/I 02/1 02/1 138/1 02/1 611/3 02/1 81/1 02/I 11/1 S2/1 02/1 42/1 87/1. 42/1 02/1 42/ I 85/I 42/1 141/1. 4271 111 1 /1 42/ TI/1 61 2/1 82/1 87/I 133/I 87/1 T2/1 07/1 84/I O2/1 83/1
DO
O2/1 T2/I
7 O O I S
11 12 1 3 1 4 I D
le 17
le
DI 32 31 34 30 36 37 38 39 40 41 42 43
02/1 84/1 88/1 83/I B8/1 T2/1 88/I 84/i 8711 S4/1 02/1, 04/I
13 8/1. 04/1 111 711. 89/1 87/1 R2/1 B7/I 810/1 02/1 89/1 02/1 02/1 02/1 818/1
:ONTIN.JETT/4 GNA0P-2
THU. 87 JUN 1988
1
FIG. 2.9 Minimal cut sets (up to third order) for the system illustrated in Fig 2.5
TYPE 3 A cut set where supply is lost to the load point being evaluated due to one component actively failing whilst the remaining components of the set are out of service. Supply is restored by isolating the actively failed component and closing the circuit-breakers that were opened due to the active fault. TYPE 4 A cut set similar to TYPE 3, but including one stuck (NC) circuit-breaker in the protection zone of the actively failed component (i.e., failing to operate on demand).
order minimal cut sets, 73 are of TYPE 1 and 48 are of TYPE 2. One or more of the following restoration procedures are included in the calculation of the AOT index for the load point being evaluated. The selection of the appropriate restoration mode(s), from those available, is on the basis of shortest time for restoration of supply to the load point from a normal (unlimited energy) source. Only where an alternative path leading to an unlimited energy source is not available is restoration from an LES considered. These restoration procedures are: • Repair.
TYPE 5 A cut set with the same component failure modes as for TYPE 1, but where the supply is restored to the load point being evaluated from an LES, via a (NO) path. Figures 2.8 and 2.9 provide separate lists of cut sets on which failure events of TYPE 2 are based. It can be seen that, of the total of 61 first and second order minimal cut sets, 49 are of TYPE 1 and 12 are of TYPE 2. Of the total of 121 first, second and third 100
• Replacement. • Switching or isolation. • Reclosing of circuit-breakers. • Closing of (NO) circuit-breakers to provide an alternative source of supply, which may include standby plant. The alternative (NO) paths may subsequently be considered to fail, or not to fail, according to the
Reliability evaluation of power systems
44 45 46 47 48 49 SO 51 52 53 54 55 56 57 50 59 60 GI 62 63 64 55 66 67 60 69 70 71 72 73 74 75 74 77 78 79 BO 81 02 03 84 85 86 87 80 89 90 91 92 93 94 95 96 97 98 99 1 00 101 1 02 :09TINUE
1 9
111 8/1 89/1 08/1 R2/1 81111 010/1 07/1 01/1 0211 01/1 00/1 G1/1 01/1 W1/I 12/1 w1/1 114/1 141/1 81/1 81/1 81/1 T1/1 1:1 3/1 82/1 12/1 81/1 T211 TI/1 12/1 82/1 04/1 81/1 04/1 TI/1 04/1 82/1 85/1 04/1. RI/1 54/I 116/I 54/1 85/I $4/1 85/1 $4/1 95/1 54/1 81/1 $4/1 R1/1 54/1 R1/1 $4/1 05/1 $4/1 86/1 $4/1 86/1 54/1 85/1 11 9/1 85/1 82/1 115/1 810/1 R1/1 89/1 81/1 R2/1 R1/I 810/1 116/1 139/1 80/1 R2/1 0611 810/1 85/1 O9/1 85/1 09/I B5/1 89/1 85/1 R2/1 85/1 R2/1 115/1 R2/1 85/1 810/1 B5/I 010/1 85/I 810/1 RIII 89/1 RI/I 89/1 51/I 09/1 R1/1 R2/I R1/1 R2/I R1/1 92/I R1/1 B10/I 01/1 810/1 91/1518/I 04/1 89/1 06/1 89/1
41/1 WI/1 w1/1 BL/I T1/I 11 2/1 81/1 T1/1 82/1 81/1 11/1 82/1 w1/1 wi/1 1.1 1 /1 wi/I w1/I 81/1 w1/1, W1/1 41/1. 8111 T1/1 92/1 51/1 TI/1 82/1 8i/1 TI/1 B2/1 81/1 T1/I 82/1 81/1 11/1 82/1 131/1 T1/1 82/1 8I/1 Ti/1
/8
GR859-2
TkU. 02 JUN 1988
1
FIG. 2.9 (ccuird) Minimal cut sets (up to third order) for the system illustrated in Fig 2.5
requirements of the engineer or the purpose of the evaluation. 2.5.9 Switching effects of component active
failure The evaluation of TYPE 3 and TYPE 4 failure events requires the determination of the switching effects of component active failures (see Section 2.4.1 of this chapter). To calculate the effect of the active failure of each component that can actively fail on the indices of the load point of interest, it is first necessary to determine he extent of the network outage that would be a consequence of each component active failure. There is an algorithm in the GRASP2 computer program which, by the use of digital search techniques, identifies and provides a listing of the protective circuitbreakers that would trip for active failure of each system component that has been specified as likely to suffer an active failure. The algorithm is based on the assumption that the nearest (NC) circuit-breakers in all branches adjacent to the actively failed component would trip to clear the fault.
Since this facility would obviously not be appropriate for all the different designs of SES and their associated protection arrangements, a facility is provided whereby the protective circuit-breakers to trip on active failure of each component can be specified manually. For large systems, this can be a very tedious operation. The choice of manual or automatic specification of 'breakers which trip' is controlled by the answer to question number 7 of Fig 2.6. On selection of the manual facility, the engineer is presented with a display on the VDU, as shown in Fig 2.10. He then specifies the appropriate component numbers of the 'breakers which trip' against each actively failed component listed. The automatic deduction of 'breakers that trip' results in the listing shown in Fig 2.11 for the system of Fig 2.5. This listing is optionally available for viewing on the VDU or for printing with the full study results output (see Section 2.5.13 of this chapter). 2.5.10 Markov state space models -
A state-space model is a diagrammatic representation
of: 101
Electrical system analysis
Chapter 2
03 04 05 06 07 08 09 1 0 11 1 1 1 3 1 I S 1 6 1 7 1 0 1 9 20 21 CLOSING
88/1 86/1 B6/1 B8/1
THAT
ARE
ELIMINATED
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CUT
A
PATHS
e
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62/$
e9.1
•
CUTS
B9/1 02/1
THAT
MAY
BE
CLOSED
9 1 0 38 39 40 41 42 43 44 45 49 74 7.5 76 77 78 79 80 01 82 03 84 85 86 87 88 89 90 91 92 99 94 95 96 97 98 DONT/1.10E
,
Y/A
99 100 101 102 103 1 04 1 05 10; 107 108 109
GR800-2
TN11, 02 JUN 195151
1
0880P-2
THU, 02 JUN 1988
1
4 4 4 4 4 4 4 4 4 4 4
:ONTINUETY/14
FIG. 2.9 (cont'd)
102
Minimal cut sets (up to third order) for the system illustrated in Fig 2.5
F
Reliability evaluation of power systems
COMPONENT S/S SI 52 53 S1 T1 T2 B1 92 83 Bl 95 96 97 98 99 B10 PI WI W2 RI
BREAKERS WHICH TRIP
PAGE 1
OF 2
1 1 1 1 1 1 1 1 1 1 1
1 1 1 1 1
OPTIONS: — REDISPLAY EL P NEXT PAGE RETURN
CRASP-2
FRI, Oi JON
1. ea
FIG. 2.10 Manual specification of 'breakers which trip'
• The discrete states in which the components of a system can reside. • The transition paths between the various states. Events TYPES 1 and 2
Failure events TYPES I and 2, involving only component passive failures, are represented by relatively si mple two state models. In the modelling of common mode failures in the analysis of SESs, the assumption is made that, where sets of components fail in common mode, they are returned to service independently after repair. The repair process on all failed components (independent and common mode) is conducted simultaneously and each is returned separately to service as soon as it has been repaired. Two state models for single and two component systems (components represented by i and j) are shown in Fig 2.12, where (u) represents 'up', the normal operating state, and (d) 'down', the failed state during repair. The two-component model (Fig 2.12 (b)) in-
dudes a second order CMF. Figure 2.13 represents a two-component, two-state system, including maintenance outages overlapping a forced outage: • REPAIR RATE (pt) for a component is the reciprocal of its repair time. • MAINTENANCE TRANSITION RATE for a component is the reciprocal of its maintenance duration. • FORCED OUTAGE is any outage which is unexpected. A two-state model for a three-component system which includes transitions due to two-component (second order) CMFs is shown in Fig 2.14. A similar two-state model for a three-component system with third order CMF transition is shown in Fig 2.15. A Markov model for a three-component system, including CMF and maintenance outages, is shown in Fig 2.16. Since the analysis techniques used for SESs are limited to events up to and including third 103
Chapter 2
Electrical system analysis
SWITCiiING EFFECTS OF COMPONENT ACTIVE FAILURES COMPONENT ACTIVELY FAILED S I S 2 3 4 1 2 1 2 3 4 5 6 7
a
9 B 10 W 1 W 2 1 P R 1 R 2 Q 1 0 2
B
BREAKERS TBAT TRIP 6 7 5 4 9 8 10 9 4 5 2 1 3 4 2 1 6 4 3 5 9 6 4 9 5 7 2 6 8 2 7 10 10 5 4 9 8 1 3 9 8 10 5 5 6 9 10 5 4 9 8
4
Fin. 2.11 Automatic deduction of 'breakers that trip'
order, it will be noticed that only third order events which include two commonly failed components can include a failure due to a maintenance outage overlapping a CMF. In developing all these Markov models to represent a SES, it is assumed that a maintenance operation on any component of a minimal cut set would not be commenced if one or more components of the same set are on forced outage or have actively failed. It is also assumed that only one component of each minimal cut set is on maintenance at any one time. Events TYPES 3 and 4
• The probability of two simultaneous active faults occurring during switching is negligible. This assumption is justified because the component switching times are relatively small. Hence the exposure ti me of the system to a second active failure is small and the probability of two overlapping active failures during switching is negligible. • The probability of two simultaneously stuck breakers in the system is also negligible. This is justifiable since the individual stuck breaker probability is normally very small, of the order 10 -3 . Such states as j(s) in Fig 2.17 are thus excluded from
For failure events involving component active failures (TYPES 3 and 4) a three-state model is used. Three-state models for single and two component systems are shown in Fig 2.17, where (u) represents the normal operating state, (s) the state after an active failure but before switching (switching state) and (r) the state after switching but during repair. It can be seen that a small increase in the number of system components gives rise to a significant increase in the number of system states, particularly for threestate models. The Markov models become very involved, particularly when second and third order CMFs are included. To reduce the number of possible combinations of
Event TYPE 5
component failures leading to state (s), the following simplifying assumptions are made:
The Markov model for second order TYPE 5 events, including overlapping forced outages (independent and
104
i(s)
all three-state Markov models used in the analysis. A three-state Markov model for three-component systems is shown in Fig 2.18. The model represents an active failure of component 1 and overlapping forced outages of components 2 and 3 due to independent and common mode failures. Similar models can be drawn for active failure of component 2 overlapping forced outages of components 1 and 3, and for active failure of component 3 overlapping forced outages of components I and 2.
Reliability evaluation of power systems system. Failure/restoration events of TYPE 1 and TYPE 2 are assessed.
(a) Two-state. one component
II
Id)
(b) Two-state, two components
p. Ci
KEY = PASSIVE FAILURE RATE COMPONENT PASSIVE FAILURE RATE COMPONENT j = REPAIR RATE COMPONENT i = REPAR RATE COMPONENT j = CMF RATE FOR COMPONENTS i AND1
.u. d. - con
n SYSTEM UP/HEALTHY STATE 1-1 SYSTEM DOWN/UNHEALTHY STATE
I) 2 12 I N\o-state models for single and mo component systems
common mode) and maintenance outages overlapping forced outages, is shown in Fig 2.19. 2,5.11 Evaluation techniques (busbar indices) Since passive and active failures are independent failures, the analysis of a system is divided into the foliov.ine parts: Part 1
Analysis considering only overlapping passive failures and using a two-state model of the
Part 2 Analysis considering only active failure and active failures overlapping passive failures. A three-state model of the system is used and si mulation of active failures and active failures in conjunction with a stuck breaker condition are performed for each component, the system configuration being changed for each simulation according to the deduced switching effects. Failure/restoration events of TYPE 3 and TYPE 4 are assessed. For failure events TYPES 1 and 2, the reliability indices of the load point are obtained by reducing all second and third order minimal cut sets to an equivalent first order cut set. All real and equivalent first order minimal cuts are then combined 'in series' to give the overall load point indices. Greater precision in the evaluation of the busbar indices can be achieved if the probability of failure of the (NO) paths available as the means of restoring supply to the load point being evaluated (i.e., TYPE 2 events), during the period they are required to function, is taken into consideration. The GRASP2 computer program can include this facility by the use of study control parameters I and 4 (see Fig 2.6). Inclusion of the failure probability of the (NO) paths requires the calculation of auxiliary indices involving the simulation of failure events associated with the (NO) paths up to the order specified in the study control parameters. These auxiliary results are then combined with the main indices for the associated TYPE 2 failure event, using the appropriate minimal cut set equations. The method of deriving the equations for each event type is fully discussed in [2].
Second order failure events (TYPE 1 and TYPE 2) There are three failure sequences for a second order failure event: (a) Failure or maintenance outage of component 1 followed by the independent failure of component 2. (b) Failure or maintenance outage of component 2 followed by the independent failure of component 1. (c) A common mode failure of components 1 and 2. The equations for the evaluation of TYPE I and TYPE 2 failure events are shown in Tables 2.1 and 2.2. Events (a) and (b) involve sequential independent failures of each component and (c) refers to common failure of both components in the minimal cut set. The equations for TYPE 2 assume that supply can be restored by either closing a (NO) path in a time t, 105
_a-
Chapter 2
Electrical system analysis
LA)
= down i m 7 rramterhance
1(d) 2(d) -
D
SYSTEM UP HEALTHY STATE
E SYSTEM DOWN UNHEALTHY STATE
FIG. 2.13 Markov state-space diagram of two components, including maintenance
Ei
SYSTEM UP HEALTHY STATE
=
up Own
SYSTEM DOWN UNHEALTHY STATE
Fit,. 2.14 Markov diagram for third order events of TYPE 1 (components 2 and 3 CMF) 1 06
Reliability evaluation of power systems
lu) = up id) = down
53 SYSTEM UP HEALTHY STATE SYSTEM DOWN/UNHEALTHY STATE
Fic. 2.15 Markov diagram for third order events of TYPE I (components I, 2 and 3 CMF)
or by completing a repair process that has already commenced. A repair process will not be started in preference to closing a (NO) path. This is a realistic assumption for two reasons. First, the greatest effort will be placed on recovering supply by the easiest achievable means, which is normally by switching. Secondly, repair times are generally much greater than switching times. Consequently, the outage time of sequence (a) for TYPE 2 is the overlapping time between repair of component I (already started) and the switching time of the (NO) path, whereas that of sequence (c) is only the switching time. Third order failure events (TYPE I and TYPE 2)
The equations for evaluating third order TYPE 1 and TYPE 2 failure events which include second and third order CMFs are listed in Tables 2.3 and 2.4. They are based on the Markov model of Fig 2.14, where it is assumed that components 2 and 3 can fail in common mode, and on the Markov model of Fig 2.15, where it is assumed that all three components can fail in common mode. Events (a) to (f) involve sequential independent failures of components 1, 2 and 3. Event (g) involves
the independent failure of component 1, followed by CMF of components 2 and 3. Event (h) refers to CMF of components 2 and 3, followed by the independent failure of component 1, and event (1) refers to CMF of all three components. Equations for the evaluation of third order TYPE 1 and TYPE 2 failure events involving overlapping maintenance outages are shown in Tables 2.5 and 2.6. Only second order component CMFs can be involved in these events. Second order failure events (TYPE 3)
The equations for the evaluation of second order TYPE 3 failure events, involving component active failures overlapping with forced outages, are shown in Table 2.7. There are obviously no events involving component CMFs. Since it is assumed that a maintenance outage would not be commenced if one or more of the components of a minimum cut set have already actively failed, there are only two event sequences involving maintenance that need be considered. The necessary equations are shown in Table 2.8. Again, there are no events involving component CMF. 107
Electrical system analysis
Chapter 2
a
SYSTEM UP'HEALTHY STATE
0
SYSTEM DOWN UNHEALTHY STATE
FIG. 2.16 Markov diagram for third order events of TYPE 1 (forced outage overlapping maintenance)
Third order failure events (TYPE 3)
Failure events (TYPE 4)
A third order event of TYPE 3 involves the outage of one component due to active failure overlapping with the forced outage of the other two components of each minimal cut set. The forced outage of the other two components can include a second order component CMF, if applicable. Equations for the evaluation of these events are shown in Table 2.9 and are based on the Markov diagram of Fig 2.18. Similar equations can be written for TYPE 3 events involving active failure of component 2, and also of component 3, overlapping forced outages. The equations shown in Table 2.10 are for third order TYPE 3 events involving active failure of component 1 overlapping with maintenance and/or forced outages of components 2 and 3. There can be no component CMFs included in these events. Similar equations can be written in respect of active failure of component 2 overlapping with maintenance and/or forced outages of components 1 and 3, and also for active failure of component 3 overlapping with maintenance and/or forced outages of components 1
The equations to evaluate TYPE 4 failure events are not tabulated. They are basically similar to those for TYPE 3 (for first, second and third order), with the active FR of the actively failed component of each minimal cut set multiplied by the stuck probability of one of the circuit-breakers protecting the actively failed component.
and 2. 108
Failure event TYPE 5 Standby plant is, by definition, always connected to the SES through a (NO) circuit-breaker. This applies so far as reliability evaluation is concerned, even if the standby system comprises, for example, a battery or inverter source, continuously float charged and connected to the system via a (NC) circuit-breaker (sometimes referred to as a 'No-break' supply system). To model the latter with the GRASP2 computer program, the (NC) circuit-breaker would be represented as a (NO) circuit-breaker with a zero switching time. If the standby plant can be considered as having an unlimited capacity to supply energy to the system,
Reliability evaluation of power systems ..■■
••••
• Component repair rates are exponentially distributed
with time.
1, Three slates one comp° .enr
The equations for second order TYPE 5 events are shown in Tables 2.11 and 2.12 and are based on the Markov diagram of Fig 2.19. Table 2.11 contains the equations for overlapping forced outages, which can include component CMFs, if applicable. Table 2.12 contains the equations for maintenance outages overlapping with forced outages; there can be no component CMFs in this case.' Equations for third order events of TYPE 5 are derived in a similar way: those in Table 2.13 are for three independent overlapping forced outages, together with common mode failure of components 2 and 3. For third order events involving three independent overlapping forced outages, combined with a third order component CMF, the relevant equations are shown in Table 2.14. Consideration of forced outages overlapping with maintenance outages results in the set of equations in Table 2.15, in which CMF of components 2 and 3 has been included. 2.5.12 Evaluation techniques (system indices)
-
-ee stales :wo components
FAILURE RATE OF COMPONENT • SWiTCHNG TIME OF COMPONENT 1 . PE PAP RATE OF COMPONENT
SYSTEM UP HEALTHY STATE SYSTEM DOWN UNHEALTHY STATE
FIG. 2.17 Three-state models for single and two
component systems
for example, a standby generator having an unlimited fuel supply or a battery having a storage capacity sufficiently large to meet the load requirements of the system for a duration greater than the longest component repair time, it would be modelled as such by the engineer and events of TYPE 2 would apply. If, however, the standby source has a limited energy capacity (see the definition of an LES in Section 2.3.3 of this chapter), the failure events to be considered are of TYPE 5. A conditional probability approach has been used in the development of the equations for TYPE 5 events. The method is fully described in [3). The following assumptions have been made: • The standby source (LES) is the only (NO) path available for supply restoration and it does not fail when required to operate. • The failure modes involve either forced outages (independent and common mode) or forced outages overlapping with maintenance outages. .• The LES time limit (t) is measured in hours.
Evaluation of the reliability of a SES in terms of the reliability of supply at its individual load point busbars is just one of the analysis techniques available. If the emphasis is placed more on the overall performance of the SES, and it is required to determine the effect of its reliability on the availability of the associated boiler/turbine-generator unit, the use of busbar indices to compare different designs of SES objectively is not appropriate. Objective comparison becomes difficult, since the various busbars have different importances so far as the output of the unit is concerned and many failure events are common to more than one busbar. To overcome these difficulties, an overall system approach is used. The independent failure events of the system busbars are considered as a set of events that include the unit independent failure events. Therefore this set of events represents the unit cut sets from which the unit minimal cut sets must be obtained. The procedure is quite complicated because cut sets of different types have to be compared. Also, the simultaneous loss of two busbars may cause a derated state of operation of the associated unit which is different from the effect caused by the loss of each busbar separately. All these features must be taken into consideration. To calculate the indices of each derated state of the unit due to the unreliability of the SES, the loss of each busbar is considered to cause one of the following states: • Total loss of the unit. • No influence on the output of the unit. 109
Electrical system analysis
Chapter 2
SYSTEM NORMAL OPERATION A
SYSTEM AFTER SWITCHING SYSTEM BEFORE SWITCHING
B
LI SYSTEM UP/HEALTHY STATE
a
n
SYSTEM DOWN/UNHEALTHY STATE
FIG. 2.18 Failure event of TYPE 3 (component I actively fails) third order (components 2 and 3 CMF)
• A loss of x% of the output of the unit, where x may have any value and may be different for each busbar or combination of busbars. Generally, the loss of two busbars is assumed to create a derated state that may or may not be equal to the derated states caused by loss of the busbars individually. It is assumed that the loss of three busbars causes total loss of the unit. The algorithm developed for the evaluation of system indices and implemented in the GRASP interactive computer programs is described in [3]. It is based on the assumption that the independent failure events of each busbar are already known. The initial part of the reliability evaluation to calculate the system indices therefore follows basically the same procedure 110
as for the calculation of busbar indices, outlined in the previous section. Here, however, every busbar of the system that is known to affect the output capability of the associated unit must be included in the evaluation. Having deduced all the feasible failure events for each busbar of the system, the following additional data is provided by the engineer from his detailed knowledge of the system and its operational characteristics: • The consequences on the output power capability of the associated unit of losing the supply to each busbar. • The consequences of simultaneously losing the supply to all combinations of two busbars, both of which separately lead to a derated state of the associated unit.
Reliability evaluation of power systems
0 SYSTEM UP HEALTHY STATE
" II,
•
".- H .
fl
FiG. 2.19 State-space diagram of two components, including maintenance — TYPE 5. Component repair rates are
exponentially distributed with time
The algorithm uses these data to calculate the average rate of occurrence or encounter (ER), the average outage duration (AOD) and the average annual outage ti me (AOT) of each feasible derated state. The overall loss of generation (LOG) in terms of MWh/year of operation, due to the unreliability of the SES, is also calculated. 2.5.13 Presentation of results
The results of a reliability evaluation study are initially presented as VDU displays selected from the following: (a) Failure rate (FR) for each load point busbar evaluated, displayed on a diagram of the selected subsystem alongside the appropriate busbar (Fig 2.20). (b) Average outage duration (AOD) for each load point busbar evaluated, displayed on a diagram of
the selected subsystem alongside the appropriate busbar (Fig 2.21).
(c) Annual outage time (AOT) for each load point busbar evaluated, displayed on a diagram of the selected subsystem alongside the appropriate busbar (Fig 2.22). (d) A full list of the input data for the selected subsystem (Figs 2.23 and 2.24). (e) A full list of the minimal paths (NC and NO), in the selected subsystem deduced for each load point busbar evaluated (Fig 2.25). (f) A full list of minimal cuts, in the selected subsystem, deduced for each load point busbar evaluated (Fig 2.26). (g) A full list of nodal failure events (with calculated indices) in the selected subsystem, for each load point evaluated. A sample from such a list is shown in Fig 2.27. (h) A full list of the calculated busbar indices in the selected subsystem, for each load point evaluated. 111
Chapter 2
Electrical system analysis TABLE 2.1 Second order overlapping forced outages (TYPE 1 and TYPE 2) Event failure sequence
Failure rate
Residence time
X
r TYPE 1
(a)
1, 2
X1X2r1
r1r2/(ri + r2)
(b)
2, 1
X2X1 1. 2
rjr2/(ri + r2)
(c)
(1 + 2)
X12
r 1 r2 /(r 1 + r2)
TYPE 2 (a)
1, 2
X1X2ri
rit c /(ri + re)
(b)
2, 1
X2Xir2
r2tc/(r2 + 1c)
(c)
(1 + 2)
X12
te
Where:
= Failure rate of component n r n --
Repair time of component n
t c = Switching time of alternative (NO) path Indices for TYPE 1 and TYPE 2 events are = EXr, a
Ti
U2 = EXr, a
r2
The list shows separately the contribution due to each of the event types (Fig 2.28). (i) A full list of the system failure events. A sample from such a list is shown in Fig 2.29. (j) A full list of system indices (Fig 2.30). Figures 2.20 to 2.30 are typical results displays for the small system of Fig 2.5 in respect of: • Evaluation of busbar indices for load point S3. • Overall system indices, assuming that the system is associated with a 660 MW unit and that each busbar/combination of busbars has the effects shown in Fig 2.29. After selective viewing of the results on the VDU, hard copies of the required pages can be taken for use in reports, etc. Alternatively, full paper printed output, which includes the results described in (d) to (j) above, can be obtained. Obviously, the full results listing is much more 112
= U /X ( 1
- 2/X2
extensive for a larger system. The list of failure events is extremely lengthy, particularly for studies involving events up to third order. In practice, therefore, the most commonly used form of results output consists of hard copies of each of the busbar indices displayed on the system diagram, together with hard copies of the input component reliability data, the study control parameters, and the summary of busbar and/or system indices (results (h) and (j) above). For important reliability evaluation work, for example, the assessment of the SESs for nuclear power stations, where there is a need for long term storage of results, it is normal practice to obtain a paper listing of the full detailed results, which is then microfilmed and archived. 2.6 Quality assurance It is fairly straightforward to check by inspection of the system diagram that, for a small system such as that shown in Fig 2.5, the minimal paths and minimal cut sets of the appropriate order are correctly deduced by the interactive computer program.
Reliability evaluation of power systems TABLE 2.2 Second order — maintenance outage overlapping forced outage (TYPE 1 and TYPE 2)
Event
Failure rate
Residence time
failure sequence
X
r
-TYPE I (a)
I", 2
XP, 2r;
r 1 r2/(r; + r2)
(b) -
2, I
X5X 1 i.
riri/(ri +ri) TYPE 2
0
(a)
1 , 2
X;X2ri
r; t c /(r; + t c )
(b)
2, I
XX1r5
r5, t c /(rir + tc)
Where:
xn
= Failure rate of component 'n'
rn
Repair time of component 'n'
tc
= Switching time of alternative (NO) path
Components out on maintenance denoted thus (') Indices for TYPE 1 and TYPE 2 events are: U; = a
a = Ul/X5
= a
a
For larger systems, due to the greatly increased number of components and branches, to do so manually would be very tedious and time consuming. However, part of the validation process for each version of the program, involves checking by inspection that the minimal path and cut set deduction is functioning correctly for at least one fairly large system. Verification of the numerical algorithms is carried out during the program development by undertaking manual calculations, using the appropriate equations from Section 2.5.11 of this chapter, of busbar and system indices for a small system, and comparing the results with those obtained from using the computer program on the same system with the same component reliability data. 2.7 Typical applications 2.7.1 Example of the calculation and use of busbar indices
This section contains a specific example of the busbar indices evaluation techniques as they were used to answer a specific question relating the design of SESs for future nuclear power stations.
The higher voltage levels (down to 3.3 kV) of the SES shown in Fig 2.31 was the initial design proposal. It was put forward as part of an overall exercise to evolve a standard design of SES and grid connection interface arrangement, which would possibly be suitable for future nuclear power stations. Depending on the exact siting of the power station, there can be a considerable variation in the reliability of the available grid connections. The frequency of LOSP (loss of off-site power) contributes to the overall summated frequency of degraded core and hence forms part of the safety case. The question raised was 'to what extent could the provision of additional on-site generation compensate for poor grid reliability?' The procedure adopted was to assume a figure of 0.075 failures/year for the frequency of loss of all grid supplies for an average duration of 2 hours and to calculate the busbar indices for the II kV and 3.3 kV levels:
(a) For the basic system of Fig 2.31, which only has standby generators at the 3.3 kV level, designed to back up the SES. (b) For the basic system, with additional standby generators on the 11 kV station boards. 113
Electrical system analysis
Chapter 2 TABLE 2.3 Third order overlapping forced outages (TYPE 1)
Event failure sequence
Failure rate
Residence time
X
r TYPE 1 1
(a)
1, 2, 3
XIX2r1X3rir2/(ri + r2)
1ir2r3/(r0"2 + r2r3 +
(b)
1, 3, 2
XiX3rIX2rir3/(ri + r3)
rir2r3/(rtr2 + r2r3 I- r3r1)
(c)
2, 3, 1
X2X3r2X1r2r3/(r2 + r3)
r 1 r2 r3 /(r 1 r2 -+ r2r3 + r3 r)
(d)
3, 2, 1
X3X2r3X1r3r2/(r3 + r2)
rir2r3/(rtr2 + r2r3 + r3r1)
(e)
2, 1, 3
X2X1r2X3r2ri/(r2 + IT)
rir2r3/(rir2 + r2r3 + r3r1)
(f)
3, 1, 2
X3k1r3X2r3r1/(r3 + ri)
rir2r3/(rt r2 + r2r3 + r3ri)
(g)
1 (2 & 3)
XIX23r1
r1r2r3/(r1r2 + r2r3 + r3r1)
(h)
(2 & 3), 1
X23X1r2r3/(r2 -I- r3)
rir2r3/(rir2 + r2r3 + r31 - 1)
(i)
(I & 2 & 3)
X123
r tr2r3 /(r 1 r2 + r2r3 + r3r1)
Where: X n
= Independent failure rate of component 'n' CMF rate for components 2 and 3
X23
CMF rate for components 1, 2 and 3
X123 rn
3rI)
= Repair time of component 'n'
Indices for TYPE 1 events are: Xi = EX, a
U1 = EXr, a
ri = U1/X1
(c) For the basic system, with additional standby generators on the 11 kV station and unit boards.
S7 and 514 — Unit 11 kV switchboards
The following assumptions were made:
S10 and S12 — Station 3.3 kV switchboards.
• The additional on-site generators provided at the 11 kV level would be standby generators and not run continuously..
S8 and S15 — Unit 3.3 kV switchboards
Description of computer produced system diagrams
Note that the actual method of producing the systems and data for each of the cases studied was to draw the complete system only for case (c) and complete the reliability data entry. Case studies (a) and (b) were then undertaken as sensitivity studies, using the 'outage' facility of the GRASP2 computer program. The plant outaged for each particular case study is shown by dotted lines on the appropriate results diagrams.
In all diagrams, the following busbar identification applies:
Results
• As normal practice in respect of the safety case, no claim is made for on-site generation from the main units.
S1
A dummy busbar to represent the common failure rate/restoration times for all the grid lines (irrespective number)
Only two of the busbar indices are of interest to permit a comparison to be made between the system with no additional on-site generation (case (a)) and the other two systems (cases (b) and (c)):
52, 53, S4 and S5
Individual sections of 400 kV busbar
• The average failure rate (FR) is of interest, since every loss of supply to any of the four 11 kV busbars leads to a reactor trip.
S6 and S13 — Generator main connections 114
Reliability evaluation of power systems TABLE 2.4 Third order overlapping forced outages (TYPE 2) Event failure sequence
Failure rate
Residence time
X
r
TYPE 2 (a)
1, 2, 3
X iX2riX31- 11- 2 /(ri + 1- 2)
r1r2t c /(r 1 r2 I- r2tc
+
tcrl)
.
(b)
1, 3, 2
X 1 X3 1. 1 X2r1 r3/(r1 +
3)
ri t e r3/(r 1 Lc + 10 3 + r3ri )
(C)
2, 3, I
X2X3r2X1r2r3/(r2 + r3)
t c r2r3/(t c r2 + r2r3 4- r3tc)
(d)
3, 2, 1
X3X2r3Xtr3r2/(r3 + r2)
ter2r3/(ter2 + r2r3 + 7'30
(e)
2, 1, 3
X2X1r2X3r2r1/(r2 + 1'1)
rir2t c /(rtr2 + r2te + teri)
(e)
3, I, 2
X3X11- 3X2r3r1/(r3 + ri)
rit c r3/(r1 t c + to- 3 + r3ti)
(g)
1 (2 & 3)
X1X23r1
rticArt + lc)
(h)
(2 & 3), 1
X 23X i r2r3/(r2 + 1- 3)
t c r2r3/(t e r2 + r2r3 + r3t c ")
(i)
(1 & 2 & 3)
X123
tc
Where: X n X23 X123
rn tc
1-
= Independent failure rate of component 'n' = CMF rate for components 2 and 3 CMF rate for components I, 2 and 3 Repair time of component 'n' = Switching time of alternative (NO) path
Indices for TYPE 2 events are: X2 =
E X, U2 = a
a
Xr, r2 = U2/12
• Average outage time (AOT) is of interest, since it gives an indication of the availability levels required of the SES to cater for the reactor post-trip (initiated by the electrical system) period. The average failure rate for those events initiated by failures within the electrical system which cannot be recovered within 2 hours is also of interest. For the safety case, this indicates the improvement in the immediate reactor post-trip period that would be gained from providing the additional on-site generation. The diagrammatic results for AOT and FR for case (a) are shown in Figs 2.32 and 2.33 respectively. Those for cases (b) and (c) are shown in Figs 2.34 to 2.37. Table 2.16 summarises both busbar indices and the (0-2 h) FR for each busbar for all three cases. The (0-2 h) FR figures were obtained by manually sorting the list of failure events and combining only those events which had AOTs greater than 2 hours. It can be seen from Table 2.16 that the effect of adding auxiliary standby generators at the 11 kV level would be to increase the average failure rates of the
11 kV and 3.3 kV boards, whilst only showing a marginal reduction in the corresponding average outage durations. A similar increase is shown in the (0-2 h) average failure rate. Both these effects are predictable, since they are due mainly to the addition of the active failure rates of the 11 kV (NO) circuit-breaker associated with the additional standby generators, and these events are recoverable within the (0-2 h) period by switching/ isolation and the use of alternative sources of supply. 2.7.2 Example of the calculation and use of system indices
This section contains a specific example of the evaluation techniques for system indices as they were used to compare the performance of two alternative proposals for the design of a SES for the Coal-Fired Reference Design in terms of the availability of the main boiler/ turbine-generator unit. It was also required to assess the cost of lost generation caused by failures within the SES over the 115
Electrical system analysis
Chapter 2 TABLE 2.5 Third order — maintenance outage overlapping forced outage (TYPE I) Event failure sequence
Failure rate
Residence time
X
r TYPE I
(a)
1 , 2, 3
XP, 2ri'X3rrr2/(q + r2)
gr2r3/(r; r2 + r2 r3 + r3rj')
(b)
1 0 , 3, 2
XI'X3r1A2r 1'r3/(q + r3)
r 1 r2r3/(r 1 r2 + r2r3 4- r3r;)
(0
2", 3, 1
X2 ■ 362,1*- 3/(r; + r3)
ririr3/(rir
(d)
3", 2,
I
xp,21-ix it- P- 2/(ri ÷ r2)
r1r2r 3 /(rir2 + r2q + 6'1'1)
(0
2", 1, 3
XpiriX3r?1/(ri + ri)
riri73/(rirl + r 2 r3 + r3rj)
(f)
3", 1, 2
X3X1r;X2r3r1/(r3 + ri)
r1r2ri./(rir2 + r3r; + *I)
(g)
1" (2 & 3)
XcX23r1
rjr2r3/(rjr2 + r2r3 + r3rj)
Where:
+ rp. 3 + r3r/)
X n = Independent failure rate of component 'n' X23 = CMF rate for components 2 and 3 In
Repair time of component 'n'
Components out on maintenance denoted thus ("3 Indices for TYPE I events are: X; = EX", a
= EX'r", a
designed life of the station for use in the cost benefit exercise to assess whether the capital cost of providing the interconnection could be justified. The basic design of SES proposed, is shown in Fig 2.38 with two variants: •
system that is purely radial top-to-bottom, with no switchboard interconnections at any voltage level.
A
• A system as shown in Fig 2.38, but having normally open interconnectors between corresponding switchboards of each train at each level within the unit system and also at the 11 kV level between each unit and station switchboard.
System conditions Since the exercise was of a comparative nature, all cables (except those used to interconnect boards in the one system) were excluded from the studies to simplify the analysis. It was assumed for the purpose of the study that the station was in the CMR condition. Thus, for example, all coal mills and fans were modelled as being in operation, whereas only one sootblower and two oil pumps were included, the remaining sootblower and oil pump being on standby. 116
= 14/Xr
One complete unit system (Unit 1 Trains A and B) and half of the station system (Station Train 1) were represented in the computer model. Figures 2.39 and 2.40 show the computer-produced diagrams for the radial system and Figs 2.41 to 2.43 show those for the interconnected system. Table 2.17 shows the correlation between the computer-generated busbar numbering system and the individual system board names. A grid failure rate of 0.039 failures/year was used for the 400 kV and 132 kV systems and failure rate data accumulated for generators of 500 MW and above were used for the 900 MW unit. It was recognised that plant maintenance policy would play an important role in this assessment and a logical maintenance scheme was assumed, which included a certain amount of in-line maintenance. To calculate the system indices, a derating factor was applied to each of the main unit boards (i.e., those at 3.3 kV and above) of each system. For example, it was assumed that loss of supply to 11 kV Unit Board 1A1 would result in a reduction in output power from the main generator of 50%. In addition, combinations of various unit boards were considered; for example, loss of both 3.3 kV mill boards was assumed to result in 100 0/o loss of unit output, whereas loss of 3.3 kV mill
Power system performance analysis TABLE 2.6 Third order
Event failure sequence
—
maintenance outage overlapping forced outage (TYPE 2)
Failure rate
Residence time
X
r TYPE 2
(a)
1", 2, 3
Xi'X2qX3ri'r2/(r1 + r2)
ilr2t c /(11'r2 + r21 c + tcr;')
(b)
I", 3, 2
>4X3r1X2ri'r3/(r1 + r3)
ri'r3t c /(11'r3 + qtc + r3lc)
(c)
2", 3, I
X 2 X3riXtr5r3/(ri + r3)
r r3t c /(rD - 3 +
(d)
3", 2, I
Xp, 2 rp+ 1 r3 r2 /(ri` + r2)
r3 r2t c /(r3 r2 + ri
(e)
2", 3, 1
X 2 X1r 2 ?■ 3rIr1/(r + ri)
ri'rit c /(r5r1 + rp. c + rile)
(0
3", 1, 2
X3X1r3X2rPii(ri. +r1)
ririt c /(riri + rit c + ritc)
(g)
1" (2 & 3)
Xj'X2311
rcte/(rj' + t c )
Where:
* c + r3tc) Lc
+ r2 lc)
X n = Independent failure rate of component 'n' X23 = CMF rate for components 2 and 3 r n = Repair time of component 'n' t c = Switching time of alternative (NO) path Components out on maintenance denoted thus (")
Indices for TYPE 2 events are: = EX", U = EX"r", r = 1.1;Al a a
board IA and 11 kV fan board 1B would result in a loss of 50; output. Loss of output due to maintenance of the main generator was not included in the system indices calculation, since this is usually a planned outage and is common to any auxiliary system. For the purpose of this analysis, loss of supply to unit boards at the 415 V level was not considered to cause loss (total or partial) of output, due to the difficulty of handling the large number of such boards and combinations of them with the GRASP computer program. However, since the analysis was comparative and the omission was made in both systems, the effects of the omission are negligible. Results
The system indices calculated for the radial system ER and LOG are shown in Fig 2.44 and those for the interconnected system are shown in Fig 2.45. The indices show that, although the frequency of encounter ER of the derated states is fractionally higher for the interconnected SES than for the radial system (0.28 encounters/year at 100% and 0.37 at 50% against 0.27 and 0.33, respectively), the loss of generation (LOG) is lower by approximately 25 GWh/year. With
replacement generation costs assessed at £25 per MWh, there would be a saving of £625 000 per unit per year or £37.5 million for a two-unit station over a 30 year life if the interconnected design of SES is used.
3 Power system performance analysis
3.1 Load flow analysis 3.1.1 Introduction
Load flow analysis is used to assist in planning, designing and operating power networks. The network or system is modelled in its steady state operating modes, then the voltage at each busbar or board and the power flow in each branch or circuit is calculated. Particular attention is being paid here to the analysis of power station electrical systems. If a SES fails to provide sufficient power to motor drives or other equipment, then generating output may be lost completely or be significantly reduced. There are economic penalties associated with the loss of generation and there may be a hazard to plant safety. Thus, it is essential to have 117
Chapter 2
Electrical system analysis TABLE 2.7 Active failure overlapping - with forced outages — second order (TYPE 3) Event failure Sequence
Failure rate
Residence time
X
r TYPE 3
(a)
la, 2
)4X2s1
sir2/(s] + r2)
(b)
2, la
X 2X al r2
sI r2/(s1 + r2)
Where: X n = Independent failure rate of component X na
= Active failure rate of component 'n' Repair time of component 'n'
rn
sn = Switching/isolating time of component 'n' Indices for TYPE 3 events are: X3 = EX, U3 = EXr, r3 = U3/X3 a a
TABLE 2.8 Maintenance outage overlapping active failure — second order (TYPE 3) Event failure sequence
Failure rate
Residence time
X
r TYPE 3
2, 1 a
X 2" Xj r2"
sirl/(si +
(b)
l", 2a
Ai'X2alii
r;s2/(r; + s2)
Independent failure rate of component
Where: X n
failure rate of component 'n'
X
r n = Repair time of component 'n' Sn
= Switching/isolating time of component 'n'
Component on maintenance indicated thus (")
Indices for TYPE 3 events are: =
118
ri)
(a)
EX", a
U
EX"r", a
r
= 115/Xi
Power system performance analysis TABLE 2.9
Active failure overlapping forced outages Event failure sequence
—
third order (TYPE 3)
Failure rate
Residence time
X.
r TYPE 3
(a)
la, 2, 3
XjX2s1X3s1r2/(sl+r2)
sir2r3/(sir2 + r2r3 +r3st)
(b)
la, 3,2
XIX3s1X2r3/(si + 1- 3)
str2r3/(s1r2 +r2r3 +r3s1)
(c)
2, 3, la
X2X3r2Xjr2r3/(r2 +r3)
sIr2r3/(str2 +r2r3 +r3s1)
(d)
3, 2, la
X3X2r3Xjr3r2/(r3 +r2)
sir2r3/(str2 +r2r3 +r3s1)
(e)
2, la, 3
X2Xjr2X3r2s1/(r2 +s1)
s1r2r3/(sir2 +r2r3+r3s1)
(f)
3, la, 2
X3Xjr3X2r3s1/(r3+st)
51r2r3/(sir2+r2r3 +r3s1)
(g)
la (2 & 3)
XjX23s1
si r2r3/(si r2 + r2r3 + r3s1)
(h)
(2 & 3), la
X23)4r2r3/(r2 +r3)
sir2r3/(sir2 +r2r3 +r3si)
Where:
X Tr =
Independent failure rate of component 'n'
Xt = Active failure rate of component I X23 = CMF rate for components 2 and 3 r n = Repair time of component 'n' SI
= Switching/isolating time of component I
TABLE 2.10
Maintenance outage overlapping with active failure and forced outage — third order (TYPE 3) Event failure sequence
Failure rate
Residence time
X
r TYPE 3
(a)
2", 3, la
XiX3r2Xtrir3/(r1 +1 - 3)
s1rr3/(siri +-sir3 +r?3)
(h)
2", la, 3
XIXMX3r1s1/(r'i+st)
sir ft2r3/(sir
(c)
3", 2, I
X;X2eiXteir2/(ri + r2)
sIrS 1- 2/(sir"3 +slr2 +r"3r2)
(d)
3", la, 2
X"3 Xf riX2rSsi/(1 +sI)
sir rir2/(siri +str2+r;r2)
Where:
X r, =
Independent failure rate of component 'n'
Xj
Active failure rate of component 1
-!- sir; +r?3)
= Repair time of component `ri' si = Switching/isolating time of component I Component on maintenance indicated thus (")
119
Electrical system analysis
Chapter 2 TABLE 2.11 Overlapping forced outages
—
second order (TYPE .5)
Residence time Event
(TYPE 5)
Failure rate
Repair rate
Restoration by component repair
Restoration from LES
A
ii
rA
rg
(a)
1, 2
XIX2r:
Al +n2
1 4t
rit c /(ri +tc)
(b)
2, 1
X2X1r2
1.4 I + n2
I/pi
r2tc/(r2-1-tc)
(c)
(I +2)
Al2
Al +n2
1 4t
tc
For each event: Average repair time r = rAP + rg (I —P) Where:
P
=
A n = Failure rate of component rn
Repair time of component 'n'
t c = Switching and start-up time of LES EL
Time limit of LES
Indices for TYPE 5 events are: X = Xa + Xb + A c U
ra
Ab rb +
Ac
rc
r = U/X
well designed power station electrical systems, so their operating voltage and frequency limits are defined; if the auxiliary plant is specified to be supplied within these defined voltage and frequency limits, then its performance will be acceptable. 3.1.2 Program construction [4,51 General remarks
The equations defining load flow in a power network can be stated and digital computation then used to solve them. A great deal of research has gone into finding the best methods of doing this. Special numerical techniques are used, the most popular being based on nodal methods of network analysis, using Newton-Raphson based algorithms to solve the network equations. Gauss-Seidel based algorithms and Z-matrix methods have also been developed. These methods are discussed in detail in [6]. A set of complex simultaneous equations is set up relating currents and voltages within the network. Although the basic equations are linear, non-linearities arise for various reasons. Hence the need for an iterative numerical solution. 120
There are many ways of describing an electrical network or power system mathematically: all must satisfy Kirchoff's voltage and current laws. Nodal analysis has emerged as the method best suited to digital computation. Assuming a balanced three-phase network it is sufficient to use the positive phase sequence impedances (and hence admittances) of circuit components such as transmission lines and cables, transformers, series and shunt capacitors. These are usually represented in perunit (p.u.) notation as lumped linear complex impedances at rated system frequency. Transmission circuits may be represented by their equivalent r-networks. In nodal analysis an electrical system comprising transformers, lines, cables, inductors, series capacitors, shunt capacitors and loads is translated into a set of 'branches' expressed as impedances or admittances. Admittance values are normally used, because there are considerable advantages during computation in using admittance instead of impedance values for network branches. The busbars and switchboards are separately translated into a set of 'nodes' which serve as link points for the branches. All voltage sources (generators) are replaced by current injection at the appropriate node.
Power system performance analysis TABLE
2.12
Maintenance outage overlapping forced outages — second order (TYPE j)
(TYPE 5)
Residence time Event
Restoration from LES
Restoration by component repair
Repair rate
Failure rate
r'E'3
(a) (b)
I", 2 2", 1
X "X2 rl"
A
l
i' + n2
11 1 + n5
X5X1r5
ri't c /(r; + t e )
1//.4" -
1 t c /(r5 + tc)
1/12"
For each event: average repair time r" = r A P" + r" (1 - P") Where: P"
c
_
ti.
Xn
Failure rate of component 'n'
rn =
Repair time of component 'n'
tc
Switching and start-up time of LES
tL
Time limit of LES
Component out on maintenance indicated thus (")
Indices for TYPE 5 events are: X" = X; + X; U" = X r + X; r; r" =
These techniques are employed to reduce the amount of computation needed to obtain the solution to the load flow problem.
and at least one node is connected to ground (three nodes are connected to ground, in this example). Using Kirchoff's first law at each node, we have the following equations:
Nodal analysis
Figure 2.46 illustrates how a voltage source may be replaced by an equivalent current source. In Fig 2.46 (a) we have voltage source E with admittance Y connected to node I having voltage to ground of V. It follows that V = E — I/Y and I = as shown in Fig 2.46 (b). If we define II = YE and 12 = YV, this is shown in Fig 2.46 (c) and the voltage source has been replaced by a current source. In Fig 2.46 (d), we have a voltage source E and an admittance Y between nodes 1 and 2, then V2 — V1 = E i/Y. If now we define = —EY and 12 = + EY, this is shown in Fig 2.46 (e), and the voltage source has been replaced by two current sources. To illustrate the formation of the basic equations used in nodal analysis, consider the simple network shown in Fig 2.47. Figure 2.47 (a) illustrates a simple power system which translates to the Fig 2.47 (b) network. The network has a current injected into each node, each node is connected to at least one other node,
Yl (v a — vb) + Y4 v a = Y2 (vb
ye )
—
—
ia
Yl(v a — vb) + Y5 vb =
lb
Y3 (v c — vd) — Y2(vb — vc) = ic Y6
Vd — Y3 (Vc
Vd) = id
expressing the admittance coefficients in matrix form, the voltages as a vector and the currents as a vector gives:
—
yi + Y4
—Y1
0
0
va
la
—Y1
Yl+Y2+Y5
—Y2
0
vb
ib
0
—Y2
Y2 +Y3
—Y3
Vc
0
0
—Y3
Y3+ Y6
vd
or, in short form
id
YV - 1 121
▪
Electrical system analysis
Chapter 2 TABLE 2.13
Overlapping forced outages — third order (TYPE 5)
Residence time Ev en t
(TYPE 5)
Failure rate
Restoration by component repair
Restoration from LES
X
rA,
r13
(a)
1, 2, 3
XIX2riX3rir2/(ri 4 r2)
Up
rir2t e /(rir2 + rite + r21 c )
(b)
1, 3, 2
Xik3r1X2rir3/(r1 + r3)
1/A
rir3t e /(rir3 + rit e 4 r3( c )
-
--
-
(c)
2, 3, 1
X2X3r2Xtr2r3/(r2 I r3)
Iiii
r2r3tc/(r2r3 + r2tc + r3tc)
(d)
3, 2, !
X3X2r3X1r2r3/(r2 + r3)
1/y
r2r3t c /(r2r3 + r2te + r3tc)
(e)
2, 1,3
X2X ir2X3r2r1/(r2 t rt)
1/i,t
rir2t e /(rir2 + ritc + r2tc)
(f)
3, 1, 2
X3X I r3X2r3ri/(r3 + ri)
1/A
r3ritc/(r3ri +
(g)
1, 2 + 3
X1X23r
I/A
rit c /(ri + t e )
(h)
2 + 3, 1
X23X1r2r3/( - 2 + r3)
1/y
r2r3t e /(r2r3 + r2tc + r3tc)
1- 3te
+ rit c )
For each event: average repair time r = rA P + rg (1—P) Where:
+11 2 +143
= P Xn
=
e
—
AtL
Failure rate of component
X23 = CMF rate for components 2 and 3 rn Le tL
Repair time of component 'n' = Switching and startup time of LES Time limit of LES
Indices for TYPE 5 events are: x5 = EX,
U5 =
a
EXr, r = U5/X5 a
It will be seen that nodal admittance matrix Y can be written by inspection and that, for larger networks, the matrix will he highly sparse (i.e., contains a high proportion of zero elements). The properties of the matrix are:
• Each off-diagonal element Y l k is the negative of the branch admittance between nodes i and k.
• It is a square of order (n x n), where n is the number of nodes in the network.
The matrix equation YV = I defines the injected currents in terms of network admittances and voltages. Mathematically speaking, the set of equations YV = I may or may not have a solution, depending on the characteristics of matrix Y. No solution is possible if matrix Y is singular and thus has no inverse. This happens if the system has no ground connections. If matrix Y is not singular, the ease of solution depends on whether the matrix is well conditioned; if it is, computational rounding errors will not accumulate during the numerical process. Fortunately, the admit-
• It is symmetrical (Yik = row, k'h column).
Yki,
general element
•th
• It is complex, i.e., it may contain conductance and susceptance terms. • Each diagonal element Ykk is the sum of the admittances connected to node k, including the branches to ground. 122
• In large networks, many off-diagonal elements will be zero, i.e., the matrix is sparse.
Power system performance analysis TABLE 2.14
Overlapping forced outages — third order (TYPE 5), with third order CM?
Residence time
Event
(TYPE 5)
Failure rate
Restoration by component repair
Restoration from LES
X
rik
rn
_ (a)
1, 2,3
XiX2riX3rir2/(r1 4- r2)
1/A
r1r2t e /(rir2 4- rItc + r2tc)
(b)
1, 3, 2
XiX3riX2rir3/(ri + r3)
Up.
rir3t e /(rir3 + rit e + r3te)
(c)
2, 3, 1
X2X3r2X1r2r3/0 . 2 + r3)
1/kt
r2r3t c /(r2r3 + r2te + r3te)
(d)
3, 2, 1
X3X2r3X1r3r2/(r3 + r2)
1/ p,
r3r2t c /(r3r2 4- r3tc + r2te)
(e)
2, 1,3
X2Xir2X3r2rii(r2 + rI)
1/p,
r2rit c /(r2ri + r2tc + rite)
(I)
3, 1,2
X3Xir3X2r3r1/(r3 + rI)
Pp
r3rit c /(r3ri + r3t c + rite)
(g)
1, 2 + 3
X 123
1/11
tc
For each event: average repair time r Where:
rA P + rg (1 l =
P
2
Al + 1 2
—
P)
4
1 3
=
= X123
failure rate of component 'n' CIMF rate for components 1, 2 and 3
rn =
Repair time of component 'n'
tc
Switching and start-up time of LES
tL
Time limit of LES
Indices for TYPE 5 events are: 8 8 X5 = EX, U5 = EXr, r5 = U5/X5 a a
tanee matrices derived from power station electrical systems are well conditioned, also one or more voltages on the system are specified, usually the supergrid and/or grid voltage. These factors remove the problems associated with ill-conditioned admittance matrices. The specified voltage can now be eliminated from the nodal equations. Assuming for convenience that the first node voltage is known, and considering the equation I = YV, the new equations become: lk
Ykl
VI =E YkiVi
for k = 2 to k = n
The set of equations can then be solved using one of the available techniques, some of which will be briefly described later,
Busbar type definitions There are three basic types of busbar defined in load flow analysis: • PQ busbar, where net active (real and reactive power) are specified; i.e., the watts and VARs supplied from generation sources, minus those consumed by loads at that busbar. This is normally a busbar where only load is connected. • PV busbar, where net active power and voltage magnitude are specified. Net reactive power is not specified and its value for the busbar emerges as part of the load flow solution. Typically, this is a busbar where generating plant or synchronous compensation is connected and the voltage magnitude is controlled by regulating the reactive power output of the generator. 123
▪ •
Chapter 2
Electrical system analysis TABLE 2.15
Forced outages overlapping maintenance — third order (TYPE 5)
Residence time Event
Failure rate
(TYPE 5)
Restoration by component repair
Restoration from LES
X"
rA"
113
(a)
l", 2, 3
Xi'X2r 1 'X3ri'r2/(ri' + r2)
1/y"
rjr2t c /(r; r2 +- CI t c + r2 tc)
(b)
/", 3, 2
Xi'X3r 1 'X2il'r3
4 r3)
l/A"
rcr3t c /(r i r3 + rct c + r3(e)
(c)
2, 3, 1
XY X 3 T5X 1 q r3 /( .5 + r3)
1/A"
rir3t c /(111- 3 + rp c + r3t e )
(d)
3", 2, I
X3X2riX1rir2/(ri + T.))
1/it"
ri. r2t c /(r3r2 + qtc + r2lc)
(e)
2", 1,3
.X . ''XA riX3 *i/(ri' + ri)
1/a"
Tirit c /(rri + r5t c + rite)
(f)
3", 1,2
X3X1r3X2ri'ri/(ri' + r1)
1/g"
ti r 1 t c /(r3r i i- tit c + r t tc)
(g)
2", 2 +3
X "X23 II' I
1/p,"
rjt c /(ri + t e )
/(r1'
-
For each event: average repair time r" = r A" P + r (1—P) Where:
f4 2 + A3 or it 1 + 1.4 '2 + A3 or AI + Az
t"
P
e
—
A tL
X n = Failure rate of component 'n' X23
= CMF rate for components 2 and 3
rn
Repair time of component 'n'
1c
= Switching and start-up time of LES
IL
= Time li mit of LES
Component out on maintenance indicated thus ('')
Indices for TYPE 5 events are: X; = EX", a
U
=
X"r",
r
= 1.4/XE
a
• Slack busbar.
This is a busbar nominated by the analyst from the PV busbars for analysis purposes only. There is only one slack busbar on each system. Voltage magnitude is specified, but the net active power is designated as unknown. This is because, prior to solving the network equations, the system losses are unknown and it is not possible to specify the total generated power exactly. During analysis, these losses are assumed to be taken from the system at this busbar. The busbar with the greatest amount of generating capacity connected is usually chosen to be the slack busbar.
Complex variables
—
definitions
The complex variables in load flow analysis are the voltage and current at each busbar or node. These are 124
defined by the linear nodal equations I = YV and the busbar constraints, as follows: (a)
A t a PQ busbar V I* = (net active power) + j (net reactive power)
(net active generated power x net active power supplied to loads) + j (net reactive generated power — net reactive power supplied to loads) at that busbar. (h) At a PV busbar Re VI* = net active power (Re = real part of) = (net active generated power — net active power supplied to loads) at the busbar. and IV! voltage specified at that busbar VI = modulus of V).
Power system performance analysis
FIG. 2.20 Reliability analysis of failure rate (FR)
(c) At the slack busbar V =
—
presentation of results
• Voltage magnitude at slack and PV busbars. • Net active power input at PV and PQ busbars.
voltage specified at that busbar
• Net reactive power input at PQ busbars. Footnote: Complex power S = P -s-jQ, and V = and I = Ifleil l* is defined as II: e and called the complex conjugate of I The product VI * = S because VI * = I VI = IVI III
III e –ii I)
= = IVIII1cos 4, +jVfl sin 01 = P + jQ si milarly V * I can be
shown to
equal
P – jQ .
• The impedances of network branches. (Circuits or transmission lines, transformers, series and shunt reactors, static capacitors. Transmission circuits with significant charging currents are represented by a pi network, i.e., a series impedance and two shunt capacitances, one at each end of the circuit.) The data outputs are: • Voltage magnitude and angle at PQ busbars. • Voltage angle at PV busbars. • Active power generation at the slack busbar.
Simplified system representation data requirements and outputs
A simplified system representation has the following data input requirements for analysis purposes:
• Reactive power generation at the slack and PV busbars. • Power flows at both ends of each network branch. • Losses in each branch and total system losses. 125
Electrical system analysis
Chapter 2
RELIABILITY ANALYSISAVERAGE OUTAGE TIME(H)
FIG. 2.21 Reliability analysis of average outage duration (A0D)
Solution of network equations As mentioned earlier, the solution of the network equations in matrix form developed from the nodal representation of the power system is done by computer programs, using one of several methods. These include the Gauss-Seidel method, the Newton-Raphson method and the fast-decoupled method. These are now briefly described.
—
Yil
VI
—
(i - 1) E Yu, V
1i
where p is the iteration number. 126
(PS!
E
Yik Vr 1 )/Yii
jQS, P)/V7
(Superscript SP --specified value) and substituting for I; in the above: V;? =
(Pr— iQr) v7
k=0+1)
presentation of results
Assuming for the moment that all busbars other than the slack busbar are the PQ type, for a PQ busbar:
Gauss-Seidel method This is one of the easiest methods to program. It is adapted from the Gauss-Seidel iterative method of solving simultaneous linear differential equations. Nominating the slack busbar as number I, purely for presentation purposes, the algorithm is:
—
(i -1)
n
P YilVi - _E YjkV k - E
k=2
k =6+ I)
Yik \q - I
/17 i;
[
for k = 2 to k = n
(2.1)
This algorithm can be applied iteratively until convergence is reached. If there is a PV busbar present, it is necessary to calculate QT) before the above algorithm can be used. This is done by calculating: I r i = E Yik k =1
(Superscript P = the last calculated value(s))
Power system performance analysis
— RELIABILITY ANALYSISANNUAL OUTAGE TIME(H/YR)
FiG. 2.22 Reliability analysis of annual outage time (AOT) — presentation of results
and Qr 1 = Im [Vr 1 x IF -1 1 (Im = Imaginary part of and superscript P- I = the last but one calculated value) and Qi can be used in Equation (2.1). Finally, for PV busbars, the calculated value of V? is reduced to its original specified value without changing its angle. A logic flow diagram for the Gauss-Seidel method is given in Fig 2.48. The diagram illustrates the successive stages in the computation. Once the initial data are read into the computer and the iteration counter set to zero, the program calculates the voltage at each node in turn. It then compares the set of voltages just calculated with the preceding set of calculated voltages. If the two sets of values are within a predefined tolerance, then the solution is said to have converged. If convergence does not occur, a further iteration takes place and comparison between the two most recent sets of voltages is made. At some stage either convergence is achieved, and the results of the analysis are displayed, or the preset maximum number
of iterations is reached. In that case, a message is displayed to the user informing him that the maximum number of iterations has been reached without the solution converging. (The user then seeks the reasons for this.) To reduce computation time, an acceleration method can be inserted into the program in conjunction with the process described. One method is to project each voltage variable linearly in the direction the solution is seen to be moving. This may require additional storage and care must be taken not to 'over project' the variables, otherwise no solution will emerge. Newton Raphson method -
This method is based on the Newton-Raphson general algorithm for the solution of a set of simultaneous nonlinear equations. F(X) = 0, where F is a vector of functions f1 to f n in variables x1, to xn At each iteration of this method, the non-linear problem is approximated by a linear matrix and solved for X. 127
▪ Electrical system analysis
Chapter 2
• • •
INPUT OATA FOR SUBSYSTEM NUMBER
000
DATA
TO
CALCULATE PATHS AND CUTS
NUMBER
OF
BRANCHES • 7
EOuIvftLENT SYSTEm NO.
0-ENO
5-END
t (
i t 2)
12/1 SIll
SI/1
3 •
(
3)
41/1
(
4)
142/1
5
( (
5) 6)
$2II
02/I $4/1
04/1
$3/1
(
7)
03/1
$4/1
BRANCN NUMBER
2
76
TNE FIRST
COmPONENTS
53/1 S1/1
510/1
2 BRANCKES ARE ASSUMED UNIDIRECTIONAL
SOURCES CONNECTED TO NODES : hi 2
56111041110 EFFECTS OF COmPONENT ACTIVE FAILURES COMPONENT ACTIv LY FAILED 1 2 3
BREAKERS
THAT TRIP. 2
9
58
4
4
2 2
3 2
2 3
a 9
5
6
4
•
7 6
7 9 1 0
2 1 2 2
NORm4LLY OPEN P I
7
1
4
1
c,
7
5
9 2 2
10
5
4
8 5
I D
9
9 5 7
10
9
3
4
5
4
9
COMPONENTS
:ONT/NuE'IYIN
06459-2
FR/, 03 JUN 1988
I
FtG. 2.23 Input data to calculate paths and cuts, and the switching effects of component active failures
F(XP -1 ) = - J(XP - I) x AXP i.e., AXP = -1.1(XP
-1
)]
-
I F(X 1 ' -1 )
X is then updated by XP = XP - I + XP The square matrix J is the Jacobian matrix of F(X). This contains partial derivatives and has general element.
a fi ax k
for ith row, k' column
There are several ways to write the load flow equations; one popular way is to substitute for 1,, obtained from I = YV, into the PQ and PV busbar equations given earlier. The Newton-Raphson method is widely used and is efficient in solving large networks. Convergence is rapid when approaching correct values. Efficient solution is very dependent on accurate calculation of the elements in the Jacobian matrix. This matrix is sparse, and this property is exploited by use of sparsity-programmed ordered elimination. This means the way in which rows 128
and columns are written is changed, and only non-zero elements of the Jacobian matrix are stored and operated on. This is difficult to program but improvement in solution efficiency makes it worthwhile. Fast decoupled method
Based on the Newton-Raphson method, this solution takes advantage of two practical characteristics of power systems: • That active (watt) power flow between nodes is strongly dependent on the difference in phase angle between nodes. • That reactive (VAr) power flow between nodes is strongly dependent on the difference in voltage between nodes. If Newton-Raphson is formulated as: [AQ P
— = A
ef) AV V
Power system performance analysis
COAP0NEAT ------1 2 3
2 3 5 6 7 8 1 0 1 1 1 2 2
IFS -
0.0090 0.0030 0.0030 0.0030 0.0700 0.0200 0.0120 0.0120 0.0120 0.0120 0.0120 0.0120 0.0120 0.0120 0.0120 0.0120 0.0750 0.0750 0.0120 0.0200 0.0200 0.0040 0.0040
AFR --0.0030 0.0090 0.0030 0.0030 0.0140 3 • 01 •0 0.0050 0.0050 0.0050 0.0050 0.0050 0.0050 0.0050 0.0050 0.0050 0.0050 0.0100 0.0200 0.0050 0.0140 0.0140 0.0040 0.0040
MT --48.0000 48.0000 48.0000 48.0000 120.0000 1 20.0000 48.0000 36.0000 46.0000 36.0000 36.0000 36.0000 36.0000 36.0000 36.0000 36.0000 2.0000 2.0000 36.0000 1 20.0000 1 20.0000 24.0000 24.0000
ST --. 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000 . 0000
SP
AT --8.0000 8.0000 8.0000 8.0000 72.0000 72.0000 24.0000 24.0000 24.0000 24.0000 24.0000 24.0000 24.0000 24.0000 24.0000 24.0000 30.0000 30.0000 24.0000 72.0000 72.0000 0.0000 0.0000
0.0010 0.0010 0.0010 0.0010
9.oaLo 0.0010 0.0010 0.0010 0.0010 0.0010
0.0010
AR -0.5000 0.5000 0.5000 0.5000 L.0000 1.0000 L.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.6000 0.0000 0.0000
CONAON mODE FAILURE DATA
THERE ARE NOT G.A.F. DATA
INCONPATIBLE COAPONENTS NONE
CONTROL PARANETERS DO N/0 PATHS FAIL 62E8 REQUIRED TO DPERATE , . 5923009 NumBER of OvERLAPP/NG OuTACES DO YOu HAAT TO CONSIDER STUCK BREAKERS , APE THE 0811,060 EvENTS OF Ni0 PATHS OF FIRST ORDER , THE mAxImum PERMITTED NuNBER OF 14/0 BREAKERS IN A 300E4 PATH DOES THE $YSTEM CONTAIN INCOAPATIBLE COMPONENTS , 00 YOu HAAT THE PROGRAA 70 DEDUCE THE BREAKERS WHICH TRIP DURING AeF
,
A 2 Y Y 2 N I
0000P-2
FR:. 83
JUN
1 986
66439-2
142
JUN
533
FIG, 2.24 Reliability and CMF input data
2000 CONNECTED TO NOOE HISSER 0
3 /62130001E5 ND. 1
LIST IF SYSTEN PATHS
N096E0 OF FATHs . 4 CO ,, PONEHT NumBERS 00/1 S1/1 52/1 02/1 2 1 S0/1 04/1 22/i 42,1 0 5 4 53/1 01 , 1 111/i 2 3 PATHS NOFAALLY oFEN 53/i 64/1 52/1 02/1 2 5 4
.
02
1
FIG. 2.25 List of system minimal paths 129
Electrical system analysis
Chapter 2
LOPS CONNECTED TO NODE NUMBER S 3 /SUBSYSTEM NO. 1
LIST OF CUTS 11)48E8 OF CUTS . 61 CUT 1 2 3
COmPONENT NumEERS $31L S1/1 52/1 81/1 W2/I 5171 837i 51/1 T2/I
4
5
S1/I 84/1 7
5111 $4/1 SI/I 89/1 S1/I 02/1
9 L O
1 1
si/1 elo/L 81/1 01/1
1 1 1 1
2 3 4 5
52/i 87/1 52/1 02/1 5211 8811 52/1 WI/I
22 23
U2/1 02/I 1) 2/I 88/1 8211 81/1 w211 8111
52/1 81/1 52/I 11/1. 52/1 82/1 W2/I 67/1
1 6 17 1 8 I N 20 21
42/I T1/I 42/1 8271 87/1 83/1 87/1 T2/1 87/1 84/1 02/1 83/1 02/I 12/1
24 25 26 27 28 29 30 31 32 33 34
02/1 84/1 8811 83/1 88/1 T2/I 8811 84/1 11 7/1 04/1 0271 $4/I 88/1 $4/1 87/1 89/1 87/1 02/I 87/1 B1011 0211 89/1 0211 82/1 02/1 81011
15 36 37 39 39 40 41 42
:90777,u2
,,
43
,6 G805P-2
44 45 46 47 48
88/1 88/1 88/I 87/1 02/1 88/1 83/1 T2/I 8411. 83/1 83/1
49
50 51 52 53
54 55 56 57 58
83/I T2/I 12/1 12/1
59 60
C u TS
1m41
El ARE
ELIA/mATE0 CUT 8 9 1 0 38 39
01
CLOSING
4
A
PATHS
THJ,
02
JUN 1060
1
89/1 0211 810/1 01/1 01/1 01/1 81/I W1/1 8111 81/1
TI/1 02,1 81/1
Ti/I 82/i 84/1 81/1 04/1 T111 84/1 82/1 NORMALLY OPEN PATH
THAT
495
60
CLOSED
4 4 •
4 I)
•1 42
4 4
43
44 45
4
46
4
4
06900-2
FIG. 2.26 List of minimal cuts
130
THU,
02
JUN 1988
I
Power system performance analysis
• •
•
LOAD
CONNECTED TO MODE MURDER 6
3 ISUOSYSTEM $0.
I
•
................................. R 6LIAOILITY RESULTS
EvENT
FORCED
F.
AY.
RATE
14/1)0. S 3/1
'PILED
S1/1
S2/1
11/1
02/1 CUT
S1/1
1
S1/1 S1/1 51/1
C UT
03/ OUT T2/1
OUT 04/1 OUT 14/1 CUT 69/1
0.30008E-02 0.96630E-07
OuRnTION
0.008000
0.27397E-85
8.688710
el
0.44521E-04
0.54911E
91
0.13699E-04 0.93790E-04 0.13699E-84
0.12942E-05
0.11507E-05 0.34521E-06
6.2)9971-05
8.12210E 0.80871E
00
0.931560 8.666080
01
0.
22100
02
0.98638E-07
0.60009E 8. I22100 0.549110
8.976760
00
8.908270
00
0.970700
00
0.1819000
92
0.295711
02
6.160000
92
0.20571E
02
0.192000
01
0.240000
82
8.123430
6.342860
92
0.290430
0.29571E
02
8.122180
0,109470
01
0.426570
0.184820
81
0.189470
01
0.42657E
0.33716E-0 0.11372E-0 8.32437E-04 0.31710E-8 0.12761E-04 0.15761E-0 0.71014E-0 0,16737E-03 0.15711E-0 0.71014E-0 6.18737E-83
0.24839E-0 0,94605E-0 0-1690A0-03
02
0.39452E-0 0.77801E-83
02
0.71014E-0 0.16737E-03
01
0.71971E-0 0.10516E-02
0.69041E-06 0.113120
0.21671E-0
0.12761E-04
82
02
8.39041E-05
0.71014E-6 0.16737E-03
8.24447E-03
0.3904 10-00
0.24658E-03
02
01
0.34021E-06
0.13699E-B4
0.240000
0.39452E-0
0.77882E-83
02
0.11507E-85
0.240566-83
02
0.94685E-0
0.10959E-04
0. 39452001
0.13699E-64
0.203710
0.24E56E-0
6.109080-03
01
0.34521E-06
0.13790E-B4
42
8.23671E-0
0.10959E-04
8.14521E-06
6.13699E-84
0.042860
00
0.96630E-07
0.44521E-04
82
0
00
0.16787E-04
8.939970
0.13699E-04
0.240B8E
02
0.337900-04
0.18265E-05
81
82
00
0.13699E-04
8.192000
0.11400E 0.00000E
02
0.931560
0.18265E-85
02
OUT, TINE
0.24447E-83
0.13699E-04
0.13699E-04
8.240000
0,1 T . TINE
0.18707E-01
0.34521E-06 0.96630E-07
02
0.123480 02 0.230430
TOTAL
TOTAL
0.400000 GB
0,11507E-G5
S2/i
CUT 61/1 CUT 52/1 T1/1 CUT S2/I 82/1 OUT N2/i 67/1 OUT N2/1 02/1 OUT 14 2/1 80/1 OUT CONTINUElYIN
00
As.
0.39452E-06
0.34521E-06
S2/1
0.90000E
RATE
0,12842E-05
OUT m/0 PATH CLOSED OUT Si/1 11 2/2 1/0 O.I.Ti4 CLOSED OUT Si/1 610/1 ..6 /0 AATW CLOSED 01/1 Si./1 CUT S2/i 67/1 OUT S2/1 02/1 OUT S2/1 00/1 DuT
01/1
F,
DURATION
0.16408E-0 0.10265E-03
04
0.71971E-0 0.10516E-02 58450-2
PRI.
03
JUN
1988
I
Fro. 2.27 List of nodal failure events
Representation of transformer with off-load taps
and Jacobian matrix J is partitioned A B aik = -.3AP1/a9k b1k = -V1,-(3APi/aVk
D eik = -a AQi/a0k dik =
-
vk•OAQi/i3Vk
then it is sections A and D which strongly influence the solution. If sections B and C are approximated
to zero, there are now two separate equations: LP = ALTO and AQ = DAV/V. This is known as decoupling. The fast-decoupled method has some advantages over Newton-Raphson: • No recalculation of the Jacobian matrix is necessary. • Speed is some 5 times greater. • Higher initial convergence in most cases. One disadvantage is worse convergence close to the solution.
A transformer having nominal tap setting is, for nodal analysis purposes, represented as a simple lumped impedance. However, in power systems, transformer taps are often set to an off-nominal value. This requires some modification to the nodal analysis techniques previously described. The vast majority of tappings used are in-phase, but occasionally phase-shifting tappings are used. In-phase tappings can be accommodated by simple changes in equivalent circuits. Phase-shifts are more difficult. The admittance matrix Y is no longer symmetrical and major changes must be made to the analytical processes. One method of accommodating off-nominal tappings is to incorporate the off-nominal tap representation directly into the admittance matrix. This is done as follows. Consider the general case of a transformer with an arbitary complex tap ratio a' + jb' between two busbars (or nodes) i and k (Fig 2.49 (a)). Replace this by an ideal transformer with nominal admittance Y i k, inverting the turns ratio for analytical 131
Electrical system analysis
Chapter 2
•• • •
REL1ASILITY INDICES FOR NODE S 3 igull002TEN NO. 1
FORCED FAILURE RATE
0.10189E-01
(OUTAGES PER YEAR)
FORCE() OUTAGE AVERAGE DURATION
0.80546E 01
(HOURS)
FORCED OUTAGE TIME PER YEAR
0.161.06E 00
(POURS PER TEAR)
FAILURE RATE DUE TO MAINTENANCE
0.67427E-02
fOuTAGES PER YEAR)
OUTAGE AvERACE OuRnTION DUE TO mnINT.
B.94170E 01
(HOURS)
TOTAL OUTAGE TInE PER YEAR DUE TO HA/NT.
0.03502E-B1
(HOURS PER VERDI
TOTAL FAILURE RATE
0.24932E-81
(OUTAGES PER YEAR)
AyERAGE OUTAGE Tint
0.90069E Al
(HOURS)
TOTAL OUTAGE TimE PER YEAR
8.22156E
BO
(HOURS PER YEAR)
CONTRIBUTION TO THE ABOVE IMOICES(uS/NC THE SHAD DINE/ASTONS)
OLE TD CUTS ELI.Im.rE0 sr
OuE TO CUTS THAT HAY BE
A REPAIR ACTION
EI,InxNATE0 CLOSING A N/0 PATH
DUE TO ACTIVE FAILURES
DUE TO ACTIVE FAILURES I A STUCK SHEARER CONO/T/ON
FFR • (CAD • FO Y•
0.31000E-02 0.46645E 02 0.14600E 00
FED • 0.1.7098E-04 FOOD • 0.9822I€ DO FOT/re 0.16792E-04
FFR • F000 • EDT/V.
0.15014E-01 0.99997E 00 B.150 14E-01
FFR
'FR 9000
0.55059E-02 0.11310E 02 0.62303E-01
'FR • 0.60501E-03 ROAD • 0.96769E 00 MOT/r• 0.66360E-03
mFR • m040 • nOTIF.
0.55023E-03 0.97245E 00 0.53507E-03
rIFT1 • 0.76712E-06 ROAD • 8.97103E 00 1400/Y. 0.74490E-06
TED • AOT • 10T/T•
TFR • OUT • TOT/V.
0.15564E-01 0.99900E 00 0.15519E-01
TFR AOT • TOTer•
•
TFR • 0.60360E-02 NOT 0.241200 02 T01/0. 0.20830E 02 IONTTALET+,4
0.70294E-03 0.96804E 00 0.68047E-03
0.29019E-04 FOAO • 0.9999110 00 POT/Y. 0.20019E-04
GRASP-2
0.20787E-04 0.99921E OD 0.28764E-04
FRI,
03
JUN
1 988
1
17 n3. 2.28 List of calculated busbar indices
convenience, Fig 2.49 (b). Suppose the transformer is on nominal tap. The ideal transformer is eliminated and the nodal equations for the network branch are: Ilk = Yik (V1 Vik V i Iki = =
Vk) Yik Vk
Yik (Vi
v.ik
(2.2)
Vk) + Lik
v
(2.3)
and 1,1, = - Iki In the general case, let the voltage on the k side of the ideal transformer be V„ then V, = (a + jb) Vi and Vil k = Ilk = - (a - jb) Iki
and
Iki = Yik (Vk
Vt)
Eliminating V, (a 2 + b 2 ) Yik V, - (a - jb) Yk Vk Iki = Yik Vk - (a + jb) Yik Vi lik
132
Equations (2.4) and (2.5) showing the general case, can be compared with Equations (2.2) and (2.3) showing a transformer with nominal tap setting. Thus, in the case of a transformer with nominal tap setting, the nodal matrix is constructed by adding Yik to each diagonal term Yu and Ykk, and inserting - Yik in the off-diagonal terms Yik and Y. Similarly, for the general case with off-nominal taps, (a 2 + b 2 ) Yik is added to diagonal term Yii Yik is added to diagonal term Ykk - (a - jb) Yik is inserted in off-diagonal term Yik and -(a + jb) Yik is inserted in off-diagonal term Yki
It can be seen here that, when b 0, the nodal matrix is no longer symmetrical. In most cases, the off-nominal taps are in phase (i.e., b = 0) and the simple ir circuit shown in Fig 2.50 can be deduced from Equations (2.4) and (2.5). A second approach to representing off-nominal transformer taps is to ignore the off-nominal taps in constructing the nodal matrix and to introduce their (2.4) effects by modifying the nodal injected currents I, (2.5) and Ik by amounts li and AIk, as in Fig 2.51.
Power system performance analysis
REouCTION OF POWER OUt TO THE UNRELIABILITY OF THE ELECTRICAL AUXILIARY SYSTEM
REDuCTIos or POWER ASSOCIATED WITH EACH BuSOAR OR COMBINATION OF BuSTIARS (OATA) _______ --------------------------------------------------------------- ------8U58AR(5) 0II1 52/1 S3/1 S4/1 52/1 03/1 52/i. 04/1 53/1 54/1
REDUCTION 100.8/ 50.0/ 90.0/
100.0/ 80.0/ 69.0/
OUTPUT CAPACITY OF SORTER • BBB.Bemi, IN
THE FOLL01.1111G
TABLE:
TA! FIRST mumBER /NO/CATES ONE NOSE AT WHICH THE CUT OCCURS THE SECONO NUm6ER MAY BE: -1 DEFINING A CUT WHERE EXERT COMPONENT IS OUT -7 0EFINING A CUT WHERE EVERY COmPEINENT IS OUT BUT THE CUT MAY BE ELIAINATE0 CLOSING A m/0 PATH -2 DEFINImG A CUT WHERE ITS FIRST COMPONENT IS AcTIvELY FAILEO Am0 EVERY OTHER IS OUT 8m DEFINING A COT WHERE BREAKER BR IS STUCK. THE FIRST COmPONENT IS ACTIVELY FAILED AND THE OTHERS ARE OUT
-1
SI/ SI/ SI/ St/ 51/ 511 SI/ 51/ Si/ S11 Si! TI? 51/ COAT
_,
-I -1 -1 -1 -I -i -I -1 -1 -i -1 -1 , NUE Y / li
0,30000E-92 0.51627E-03 0.25171E-03 0.70162E-02 0.25040E-03 0.25048E-03 0.70582E-02 0.25040E-G3 0.67134E-04 0.1.5770E-03 0.86997E-04 0.15843E-83 0.33972E-03 0.15770E-03
51/J 142/1
w1/1 B1/1
42/1
T1/1
112/1
w2/1 05/J R 1/ 1 86/1 9511
55/I 55/I el/1 5 1/ 1 R1/I
AV. DURf HOURS )
0.RATE(O/YEAR1
CUT
82/1
41/1 u1 I 1 111/1 191/t T111 82/1 81/1 Ts / 1 82/1
0.46000E 02 0.10700E 01 0.45694E 01 0.406070 01 0.42200E 01 0.62208E 01 0.40067E 01 0.42208E 01 B.15310E 02 0.22710E 02 0.14464E 02 0.25908E 02 0.45401E02 0.22740E 02
7.0.7114E04/YEAR,
POWER
REOLICTION(/)
lee
o.1.4400e 80
100 100 100
0.90575E-03 0.11479E-02 0.28545E-02 0.10592E-02 0.10592E-02 0.28845E-02 0.10592E-02 0.10279E-02 0.35014E-62 0.96915E-83 0.40942E-02 0,15452E-01 0.35814E-02
citAsP-2
1 09 109
1 00 1 00
1 00 100
1 00
1 00 1 00
1 00
ritz, 03
JON
1 900
Fic. 2.29 List of system failure events
gmcouNtept RATE ARO OuRATION OF THE BERATED STATES
0,09T800/YEAR) 0.04849E-01 6.75362E-02 9.87209E-02 0.22003E-04 0.11919E-02
ExPECTE0 L955
OF ENERGY SUE
AT.OURCHOURS, 0.11022E 0.11274E 0.911 520E 0.12070E 8.91111.41E
TO THE UNRELIABILITY OF 478.252
SCATINUE
,
82 01 00 02 00
T.O.TTNE(H/YEAR)
POWER REDUCTION(/) 100 00 50 60 30
0.714706 00 0.18902E-02 0.58935E-02 0.27051E-03 0.11517E-03
THE STATION ELECTRICAL
AUXILIARY EOUIPmENT
mwmIt
Y,X
GRASP-2
FRI. 03 JUN
1 988
1
FIG. 2.30 List of system indices
133
Chapter 2
Electrical system analysis
NETWORK DRAWING AND MODIFYING ROUTINE
1325 Z1 1 232/
CS
13
15
11 9
B13
SO
GRASP -2
TUE, 13 DEC 1911B
1
Ro. 2.31 Station electrical system network used for evaluating busbar indices for future nuclear power stations
In this approach, I I and fk have to be recalculated at each iteration, but the nodal matrix is easier to formulate and remains symmetrical, even in the case of out-of-phase taps, because it contains no turns-ratio terms. Representation of transformers with on-load tapch angers
On-load tapchangers are provided to regulate voltage or, sometimes, reactive power flow. When used for voltage regulation, it is usual for the voltage at the lower voltage side of a transformer to be monitored and compared with a reference or target setting. An error signal is then used to activate a change in the transformer tap position to restore the monitored voltage to the reference setting. Because tappings are discrete steps, it is not possible to match the reference setting exactly, so a tolerance is applied to the reference setting. For example, if tappings are in 2% steps, a tolerance of ± 1% is used and no automatic tap change takes place if the re134
ference voltage is within the range 99% to 101% of its setting. To represent on-load tapchanging transformers within the load flow solution program, it is necessary to provide logic to compare target voltage with calculated voltage, then to alter tap position to correct the voltage. It is also necessary to check that the transformer tapping range is not violated during this process. This can be done between iterations until the solution converges. Practical experience has shown it is best to leave tap adjustments until towards the end of the solution process. During early iterations, voltage levels can oscillate and vary considerably. Tap changing at this stage does not speed convergence, especially with slowly converging algorithms, such as Gauss-Seidel. Because the Gauss-Seidel algorithm converges slowly, intuitively it suggests that tap changes should also be made small. An algorithm of the form an e w = a o id + a (Vr ) can be used, where a is a small constant, typically 0.05 and aoid is the transformer turns ratio at iteration p.
Yr
_
Power system performance analysis
RELIABILITY ANALYSIS—PWR LOSP — BASE CASE AVERAGE OUTAGE TIME(H)
R4$9-2
FIG. 2.32
TUE. la SEC 1900 1
Reliability analysis of average outage duration (AOD) for case (a)
In the Newton-Raphson method, convergence is rapid at later stages and a higher value of a can be used, or a different algorithm. When calculated from the above expression, a ne w requires adjusting to match the nearest discrete tap, and needs checking to ensure that the tapping range is not violated.
limit of operation. The solution then continues until convergence at a feasible result is reached. Experience shows that checking of VAr output being outside the designated range is best left until rough convergence is reached. General analytical considerations
Representation of reactive power limitation on synchronous plant
Generators have defined MVAr output limits for a given MW output. The upper limit is imposed by heat dissipation or exciter capability and the lower limit by stability considerations. A synchronous compensator has maximum and minimum VAr output ratings. When a generator or group of generators is set to control voltage at a busbar during a load flow solution, the busbar is designated a PV busbar. A check is made during the solution that the VAr output limits of the plant have not been violated. If the limits are exceeded, the busbar is redesignated as a PQ busbar and the generating plant VAr output is fixed at its
There are many methods of solving a set of simultaneous linear differential equations by numerical methods (Reference [7] is recommended to the reader who wishes to pursue this topic). The efficiency of these methods varies and a method which may be acceptable in solving one type of problem may be inefficient in solving a different type. The physical structure of the problem is very important. The set of equations describing an electrical power system network produces an admittance matrix which is highly sparse. Typically, the matrix associated with a network having 100 nodes will have about 3% of its coefficients non-zero. To process the other 97% is very inefficient and a method which only stores, 135
Electrical system analysis
Chapter 2
RELIABILITY ANALYSIS-PWR LOSP - BASE CASE FAILURE RATE (F/YR ) / x /
Flo. 2.33 Reliability analysis of failure rate (FR) for case (a)
identifies and processes the non zero terms has clear advantages. Use is also made of methods of transforming an original set of data into a set of related equations which may be easier to solve. Triangular decomposition of matrices — the coefficient matrix is factorised into a set of upper and lower triangular matrices — can speed the solution process and is used in many programs (Reference [8j provides an introduction to matrix manipulation), Ordered elimination — to keep calculation processes to near minimum — is also used extensively, and advantage is taken of the symmetry of the coefficient matrix. Reference [9] provides further reading on power system modelling. -
3.1.3 Use of programs
Typical electrical auxiliary supply systems Figure 2.52 shows an analysis diagram of the SES in an oil-fired power station and Fig 2.53 shows an 136
analysis diagram of the SES in an advanced gas-cooled reactor nuclear power station, Unless there are differences between generating units and their respective electrical auxiliary systems within a power station, it is sufficient to represent one Unit with its supply systems. The diagram is drawn by the analyst onto a computer terminal screen. To avoid unnecessary detail and to limit the size of the diagram, the analyst decides what plant he wants to represent prior to drawing the network. He will include any plant which has a significant effect on system performance; for example, he will represent all 11 kV motor drives as separate motors, but only represent a limited number of 415 V motor drives as separate motors. The remainder will be lumped together for analysis purposes. A convenient starting point in drawing the analysis diagram is the high voltage busbar to which the power station is connected. In Fig 2.52 this busbar is named '400 kV'. Later, it will be nominated as the 'slack' busbar. A 'reference' or 'source' generator is then drawn
Power system performance analysis
RELIABILITY ANALYSIS—PWR LOSP — GT ON EACH 11 KV Sir! BD AVERAGE OUTAGE TIME(H)
$13 I 22E 01
0 0.110E 01
CIONSP-2
TvE, 13 DEC 1988
I
Ftc. 2.34 Reliability analysis of average outage duration (AOD) for case (b)
connected to this busbar. This nominal generator, for present purposes, represents a tie to the grid system to be used as a power source or power sink. The power station system voltages are 11 kV, 3.3 kV and 415 V in both examples (Figs 2.52 and 2.53). The choice of voltages is based on engineering needs, economic grounds and consideration of the hardware available at the time of ordering plant. Design operating limits The normal voltage operating range of the 400 kV supergrid is 0.95 per-unit (380 kV) to 1.05 per-unit (420 kV), with a short term (15 minutes) upper limit of 1.10 per-unit (440 kV). The normal voltage operating range of the 132 kV grid is 0.90 per-unit (119 kV) to 1.10 per-unit (145 kV). Frequency, nominally 50 Hz, is normally regulated between 49.9 Hz and 50.1 Hz. System faults may give rise to variation between 49.5 Hz and 51 Hz, with exceptional variation between 47 Hz and 52 Hz for a period not exceeding 15 minutes. System faults can also lead to
step changes in voltage of 6% at 132 kV grid supply points. A station electrical system is normally designed to have an upper voltage limit of 1.06 per-unit and a lower volt-
age limit of 0.94 per-unit during steady state operation. When a motor starts, the transient voltage dip at the motor terminals should not fall to less than 0.80 per-unit and the remainder of the electrical system must remain stable and recover from the transient dip in voltage. The station electrical systems are designed to withstand the effects of electrical faults, internal and external. The worst credible disturbance normally considered is that produced by a transient fault having a clearance ti me of 0.2 second. Except for some special applications, such as PWR power station essential systems, the motors are specified to run at any load within rating over the voltage range 0.94 per-unit to 1.06 per-unit, to operate for five minutes at 0.75 per-unit voltage and be capable of running up to speed from a transient starting voltage dip as low as 0.80 per-unit. 137
Electrical system analysis
Chapter 2
RELIABILITY ANALYSIS–PWR LOSP – GT ON EACH 11 KV STN BO FAILURE RATE(F/YR)
0045P-2
TUE, 13 DEC 1980
1
FIG. 2.35 Reliability analysis of failure rate (FR) for case (b)
All other AC electrical and electronic equipment must be capable of operating continuously under such actual steady state and transient service conditions without malfunctioning or suffering damage. Design operation mode
—
transformer outages
The SES is designed to permit any one transformer except the generator transformer to be out of service, yet maintaining full station output within voltage design operating limits. Load flow analysis of the power station electrical system
Having set the voltage limits in which the SES is to operate, the system is examined in its normal steady state operating modes, and during the transition between modes. These modes are: • Unit shut down. • Unit generating its rated output at any power factor between maximum rated lag and maximum rated lead. 138
• Unit post-trip. The system is also examined with designed plant outages. The effects of starting large motors are important and strongly influence the design of the system. The large starting current drawn by an induction motor when it is switched on, causes a sharp reduction in voltage at its terminals and at its supplying board. The voltage continues to fall for a short period as other motors, fed from the same supply, draw more current to maintain their outputs at the reduced voltage. The switched-in motor must run up successfully; this means the electrical torque produced must always exceed the mechanical torque of the drive. It is particularly important in nuclear stations that some specific motors must (also) run up within a specified time after a reactor trip. The other motors subject to the lowered voltage must be able to remain stable and maintain their outputs until the switched-in motors run up and the voltage rises.
Power system performance analysis
RELIABILITY ANALYSIS—PWR LOST' — GT ON EACH 11 KV STN & UNIT B AVERAGE OUTAGE TIME(H)
DRA8P-2
TUE.
ta DEC 1980 1
FIG. 2.36 Reliability analysis of average outage duration (AOD) for case (c)
The magnitude of the voltage drop is a function of the current taken at the supplying board, and the impedance between that board and its effective supply source. Table 2.18 shows typical impedances and other data of transformers feeding and within a SES. Column 5 of Table 2.18 shows that the transformer closest to any motor drive being considered, has a much higher impedance than that of the (larger) transformers nearer to the effective supply source. It follows that the impedance of this transformer strongly influences the voltage drop at the motor terminals, and must be chosen with this in mind. Optimisation of transformer off-load tapchanger tap Positions
Once a transformer tap is set to a specific position, the voltage range at the transformer LV terminals is determined by: • The voltage at the transformer [-IV terminals. • The transformer impedance.
• The load on the transformer. It follows that, where 11 kV/3.3 kV transformers have off-load tapchangers and 3.3 kV/415 V transformers also have off-load tapchangers, the voltages at the 415 V boards of the SES are operationally determined by:
• The voltages at the 11 kV boards. • The loads on the transformers between the 11 kV, 3.3 kV and 415 V boards. When a power station is shut down, the load on the SES is usually at its minimum. This provides a convenient starting point in deciding which tap positions to adopt on transformers with off-load tapchanging arrangements. The system is modelled with its electrical load at minimum value, and 11 kV boards' voltages set to nominal value (1.00 per-unit). The offload taps of the transformers are then set, within the model, such that the 415 V (and 3.3 kV) board voltages are close to, but do not exceed, the maximum permitted voltage (usually 1.06 per-unit). 139
Electrical system analysis
Chapter 2
RELIABILITY ANALYSIS–PWR LOSP – GT ON EACH 11 KV STN & UNIT B FAILURE RATE(F/YR)
$0
0.147E 00
0
0.147E 00 GRASP-2
TUE. 13 DEC 1900 1
FIG. 2.37 Reliability analysis of failure rate (FR) for case (c)
Using these off - load tap settings, the system is then modelled at its predicted maximum load condition. Any permitted outage, or combination of outages, is also modelled and the supply system voltage must
remain within the permitted voltage range under steady state and transient (motor start or fault) conditions. The steady state and transient voltage conditions must both be attainable with the voltages at the 11 kV boards set to nominal value (1.00 per-unit). If it is shown that the system is inadequate to supply plant within design criteria, then it is necessary to identify the cause and correct this by changing system and plant parameters. Analysis of a SFS will identify the relative strengths and weaknesses of the system. Figures 2.54 and 2.55 show voltage profiles of an oil - fired power station electrical system at minimum and maximum loads, without plant outages. Loss of grid supplies It is essential to maintain cooling supplies to nuclear
140
power station reactors. Supplies to motors providing reactor cooling are normally derived from the grid system. In the event of grid failure, gas turbines or diesel generators provide power for these motors. Analysis is performed to demonstrate that a SES functions correctly in this isolated mode. A small, isolated system like this does not have the built in inertia of the grid system. This is not important in load flow studies but is a very important consideration in transient stability analysis. Figure 2.56 shows a network voltage profile with a 3.3 kV diesel generator supplying an isolated part of an electrical supply system. Reactor and turbine start sequence — voltage profile studies Figures 2.57 to 2.64 show a series of load flow/voltage profile studies for an AGR nuclear power station simulating a reactor and turbine start sequence. On the network diagram, only one reactor unit is represented. B1 is a 400 kV busbar and 83 a 132 kV
Power system performance analysis TABLE
2.16
Summary of results for busbar indices and failure rates
Average FR (failures/year) Basic system
—
Average GT
0-2 hour FR
(hours)
no additional 11 kV standby generators
11
kV Unit board
0.101
7.94
0.095
11
kV Station board
0.101
7.94
0.095
3.3 kV Essential board 2
0,142
1.34
0.139
3.3 kV Essential board 1
0.142
1.34
0.142
System with additional standby generators on each 11 kV Station board
11
kV Unit board
0.101
6.19
0.095
11
kV Station board
0.106
5.88
0.101
3.3 kV Essential board 2
0.142
1.22
0.139
3.3 kV Essential board I
0.147
1.18
0.144
System with additional standby generators on each 11 kV Station and Unit board
11
kV Unit board
0.106
5.88
0.101
11
kV Station
0.106
5.88
0.101
1.3 kV Essential board 2
0.147
1.18
0.144
3.3 kV Essential board 1
0.147
1,18
0.144
busbar. The main generator U is connected to B4 (23.5 kV). B5A, B5B, B5C and B5D are 11 kV boards. B6* are 3.3 kV boards and B7* are 415 V boards (where * represents alphanumeric symbol(s)). The 132 kV/11 kV/11 kV station transformer is a three-winding transformer. This is represented by three separate transformers connected to a common point, shown as 3W on the diagram. Figure 2.57 shows the turbine and reactor off-load. Figure 2.58 shows load flows and voltage profiles at the next stage in the start sequence. The generator is off-load and the gas circulators at 56% of their full load power (corresponding to 75 07o gas flow in the reactor). All the remaining loads, except the standby feed pumps, are assumed to be running at the generator continuous maximum rating (CMR) condition. The next study, shown in Fig 2.59, illustrates the 11 kV starting/standby feed pump on the station board (B5A) being started. In these load flow studies, the standby feed pump is represented by a shunt. The shunt impedance is set equal to the effective impedance of the motor at its start. The voltage profile shown is the lowest during the motor run-up; the increased current drawn by other motors is taken into account during the load flow algorithm solution. This study also identifies any induction motor instability — the load flow algorithm solution will not converge if the mechanical torque required by a motor drive exceeds the electrical torque available. In practice, the results given by this study would be considered satisfactory. Voltage at the board where the motor is being started is 0.867 per-unit, the lowest
voltage at any other board is 0.876 per-unit and the highest at any board is 1.034 per-unit. The next study in the sequence, Fig 2.60, shows the starting/standby feed pump up to speed and running at full load. The minimum voltage at any board is 0.975 per-unit. Physically, the next event in bringing the generator and reactor to power is to synchronise and load the generator, and increase the gas circulator loads to full power. The next study in the start sequence, shown in Fig 2.61, shows the main generator in service delivering 264 MW (40% of its 660 MW full load rating). The voltage profile is satisfactory. Figure 2.62 shows the 11 kV starting/standby feed pump on the unit board (B5C) being started and Fig 2.63 shows this pump up to speed and running at full load. Figure 2.64 is the last in this sequence of studies. It shows the voltage profile and load flows with the unit at CMR delivering maximum lagging VAr, gas circulators at full power rating and the turbine boiler feed pump running instead of the station and unit starting/standby electric boiler feed pumps. Similar sequences of studies are performed with plant outages, e.g., a station transformer outage, to show that the system functions correctly under outage conditions. Network drawing and data entry Modern analysis programs are interactive in design and allow the user to represent power system network diagrams on a screen. Mnemonic codes are available to draw and modify network diagrams. Examples are: 141
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13755
432/26N5 GENERA I OR TRANSFORMER
432/11 NV UNIT TRANSFORMER 1 20/6060MvA
T 32/1 t Ay STATION TRANSFORMER 1 20160/60 NAVA
GENERATOR SOOMW
IIK5 UNIT BOARD 181
IIKV UNIT BOARD 141
1155 -STATION BOARD IA
I SV STATION BOARD 10
TO 11111/STATION BOARD 2B
0 50.A.CW PUMP IA
11Xv FLUE GAS DE SUE PSURISA TI TFGETT BOARD 14
I D FAN LA
3 31
— — — — 0 50%•EBFP I Es
e
I 113.4901/ COAL PLANT TRANSFORMER 8 NSA
1113 + WV MILL TRANSFORMER
&Am
IIKV EGO 18F
FD FAN I A
50./.-EBFP IC
IA
11/345101 ASH 8 DUST TRANSFORMER MVA
8
I 11134
c
X-100% SOOT BLOWERS
TO 11KV STATION KV BOARD 7A
STATION AUXILIARIES TRANSFORMER 8 USA
3 3Xv COAL PLANT 0 3 30V ASk/IS DUST PLANT AUXILIARIES BOARD 1 AUXILIARIES BOARD
I 1/0/ FAN le
ID
® PA FAN i A
ID FAR PA FAN le
4100 HUNKER BOARD 1
415V ASH PLANE SERVICES BOARD I
415V COAL PLANT KISS DUST PLANT SERVICES BD 1 SERVICES BOARD 1
0
3 3KV MILL AUXILIARIES BOARD I
3 31(5 STATION AUXILIARIES BOARD 1
3 3KV FGD AUXILIARiES BOARD 10 0
0 IA 10 IC COAL MILES
415V FGD SERVICES BOARD 1415
475v PRECIPITATOR BOARD IA
[1 1 :-
ID
I E IF COAL MILLS
415KV MILL SERVICES BOARD IA
IA 18 IC 35-935. CW PUMPS
1151/ MILL SERVICES
BOARD TES
KISS GENERATOR SERVICES BOARD 1
1151/ FAN SERVICES 4155 BOILER AUXILIARIES BOARD 18 BOARD 1B
18
IC
88
415V OIL PLANT BOARD I
30 , 00x0iL HEATERS
8 4 i5V LIGHTiNG 8 SMALL POWER BOARD I IJ 415V ADmIN BLOCK BOAEID I L..JAISV DEAE RA TOR HEAT ER BOARD 1
4155 TRANSFORMER BOARD I
4155 TURBINE BOARD IA 4155 FAN SERVICES 415V BOBER AUXILIARIES BOARD I A BOARD TA
IV
30 100% OIL PUMPS
4I5V CW PUMP BOARD I
4I W FOD SERVICES BOARD I R
415V PRECIPITATOR SERVICES BOARD 1 B
(3
415 ,/ WATER TREATMENT BOARD I
4155 EURETINE BOARD lB
FIG. 2.38 Station electrical system used for evaluating system indices for a coal-fired power station reference design
L _ TO 3 3Jiv STATION AuxILIARIEs BOARD 2
Power system performance analysis
NETWORK DRAWING AND MODIFYING ROUTINE
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FIG. 2.39 Network diagram for radial subsystem I
B draws a busbar at the cursor position. G draws a generator at cursor location and connects it to the last drawn busbar. C draws a circuit from the last drawn busbar to the cursor position. T draws a circuit, which includes an in-line transformer symbol, from the last drawn busbar to the cursor position. The diagram may be recentred or resealed. Codes are available to delete unwanted network items, move network items to new locations, name busbars, and to erase the screen and redraw the diagram. Figure 2.65 shows an example of a SES drawn in this way. The drawing is of an isolated system consisting of an auxiliary generator supplying six gas circulators. Programs are structured through a series of menus which list the options open to the user at each stage of the analysis. The initial menu displays the broad options available; sub-menus are then offered which
permit detailed selection of the further options existing within that sub-menu. An initial menu, giving the main options, may be: • Construct a new network. • Retrieve a network from file. • File the present network. • Modify the present network diagram. • Edit the present network data. • Load flow calculation. • Fault level calculation. • Transient stability calculation. • Controller design facility. • Exit from the program. Options are selected by positioning the horizontal cursor of the computer terminal screen over the option required and pressing any key; alternatively, a mnemonic code may be used. 143
Electrical system analysis
Chapter 2
NETWORK DRAWING AND MODIFYING ROUTINE 84
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FIG. 2.40 Network diagram for radial subsystem 2
When the program user has drawn (and filed) the electrical system to be analysed, data is then entered to define each component. This is done either by copying data from an existing data bank, or by direct specifications. Data requirements An analyst may wish to make a preliminary assessment of an electrical system without having full detailed information about component circuits and connected plant. Programs are flexible enough to allow this. Basic data requirements for load flow analysis were given earlier in the section headed Simplified system representation data requirements and outputs. These, with transformer tapping information, are sufficient for preliminary load flow calculations. Induction motor loads may be represented as part of the net active and net reactive load at busbars. An alternative, sometimes better, representation uses the equivalent circuit parameters of the induction motors if these are available. For a given motor and MW load, 144
the program calculates the motor VAr requirement. The value calculated in this way is voltage dependent and therefore may provide a more accurate solution than that obtained by using static load representation. An even more accurate prediction of system performance can be made once plant is manufactured, when test or measured values of plant parameters become available. Comprehensive data sets can be entered into programs. To achieve greater accuracy in calculation, additional data can be processed by programs. The complete list of data which can be used is as follows: Busbar data Busbar load, MW Busbar load, MVAr Circuit data Positive sequence resistance Positive sequence reactance Positive sequence shunt susceptance Rating (used to flag overload conditions) Circuit state (in or out of service)
Power system performance analysis
NETWORK DRAWING AND MODIFYING ROUTINE CI
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Fin. 2.41 Network diagram for interconnected subsystem 1
Transformer data Initial tap position Minimum tap position Maximum tap position Tapch anger increment Target voltage (at sending or receiving busbar) Rating Voltage monitoring relay bandwidth Change of reactance with tap position Compensating resistance Compensating reactance Generator data Machihe busbar voltage magnitude Generated power, MW Generated reactive power, MVAr Status (indicates whether machine is included in studies) Automatic voltage regulator (AVR) data Not required Governor and turbine data Not required
Induction motor data
Mechanical power output Friction and windage losses Magnetising reactance Stator resistance — start (cold) Stator reactance — start (cold) Stator resistance — run (hot) Stator reactance — run (hot) Rotor resistance — start Rotor reactance — start Rotor resistance — run Rotor reactance — run Rotor inner cage resistance and reactance Rotor outer cage resistance and reactance Status (indicates whether machine is included in studies) Load torque/speed characteristic Motor contactor drop-off voltage Underspeed trip setting There are several ways of entering the above data, depending on the analysis program being used. Values 145
Electrical system analysis
Chapter 2
NETWORK DRAWING AND MODIFYING ROUTINE
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INTERDONNECTORS DRAWING AND MODIFYING ROUTINE
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FIG. 2.43 Subsystem interconnectors 146
CRASP-3O mON, 06 JON 1666
11:02:21
Power system performance analysis TABLE 2.17 Correlation between computer generated busbar numbering and individual system board names
Svmbol
System component
• Nominated slack busbar. • Maximum number of iterations in load flow solution algorithm. • Reference machine busbar name. • Reference machine identifier.
Subsystem / SI S2.3 54,7 55,6 S8,11 59,10 512,23 513,22 514,21 S15,20 516,19 517,18
400 kV busbar 11 kV Unit boards 1A1, 1BI 11 kV FGD boards IA, 1B 11 kV Fan boards 1A, lB 3.3 kV FGD auxiliaries boards IA, 1B 3.3 kV Mill auxiliaries boards IA, IB 415V POD services boards IA, 1B 415V Precipitator boards IA, IB 415V Turbine boards IA, 1B 415V Fan services boards 1A, 1B 415V Mill services boards IA, 1B 415V Boiler auxiliaries boards IA, 1B
Subsysrem 2
51,2 53 54 55 S6 57 58 S9 510 SI I S12 513 514 515 516 5/7
11 kV Station boards IA, 1B 1.3 kV Coal plant auxiliaries board I 415V Bunker board 1 415V Coal plant services board 1 3.3 kV Ash and Dust plant auxiliary board 1 415V Ash plant services board I 415V Dust Plant services board 1 3.3 kV Station auxiliary board 1 415V General services board 1 415V Lighting and small power board 1 415V Transmission services board I 4I5V CW pump board 1 415V Administration Block board 1 415V Water Treatment board 1 415V Deaerator Heater board I 415V Oil Pump board I
General
%,%;
Energy Source (Grid, Supergrid or Station Train 2) Normally-open circuit-breaker Normally-closed circuit-breaker Interconnecting cable Transformer Isolator
of resistance and reactance may be entered as per-unit values or per-cent values, based on machine rating or referred to a standard base (usually 100 MVA). Sometimes the facility exists to enter these values as ohms. Voltages are usually entered as per-cent or perunit, occasionally as volts. In addition to the plant data listed earlier, other information is required to control program runs. This i ncludes: • Loadflow convergence accuracy.
• Printout option details. Examples of data entry are given in Figs 2.66 to 2.69.
Transformer data entry Transformers in power systems usually have variable tappings, with the tapchange mechanism being designed for on-load or off-load operation. On distribution transformers in station electrical systems, off-load tapchangers are specified where the load does not vary sufficiently to cause unacceptable voltage regulation. On-load tapchangers are specified when design studies show that these are necessary to maintain system voltage within design limits. On-load tapchanging is initiated by an automatic voltage regulator or by operator action. Generator transformers have on-load tapchangers which are normally manually controlled. The generator AVR is usually in service and set to keep generator terminal voltage at (or near to) 1.00 per-unit by adjusting the generator VAr output. Supergrid or grid voltage is then regulated by varying the generator transformer tapping manually. In analysis programs transformer resistance and reactance are usually entered in the associated 'circuit data'. In practice, transformer reactance may vary over the tapping range; the variation can be linear; or it may fall to a minimum, then rise; or rise to a maximum, then fall. The variation is determined by the winding configuration. Linear variations of reactance with tap position can be entered in analysis programs. Facilities are not available at present for other variations, so the analyst must decide the best data to use. Where a transformer operates with a fixed tapping (off-load operation or no tapchange available), this tapping ratio is entered into the transformer data. When on-load tapping facilities are used, it is necessary to enter the maximum, minimum and starting tap settings and the tap step. The target voltage is entered, and whether it is the voltage at the sending busbar or receiving busbar that is to be controlled. Taps are assumed to be at the sending end of the transformer. Automatic voltage regulator relay bandwidth may be specified, as can any resistance and reactance compensator. Compensating resistance and compensating reactance are not applied in power station networks but are often used in distribution networks. Power station/grid system interface A station electrical system is normally connected to the grid and/or the supergrid. The interface, for analysis 147
Chapter 2
Electrical system analysis
CFSRD RADIAL SYSTEM 20 ST - MPSP
ENCOUNTER RATE AND DURATION OF THE DERATED STATES
O.RATE(0/yEAR)
T.O.TIMEcH/YEAR)
Av.OURCHOURS)
e.260BeE
00
9.91451E e2
0.24589E e2
0.326805
BO
0.45455E 02
0.14525E
POWER REDUCTION() 1 00
02
Se
• • EXPECTEO LOSS OF ENERCy DUE TO THE UNRELIABILITY OF THE STATION ELECTRICAL AUM/LIARY EQUIPMENT • 20738.450
116I145
•
•
f
ONTINUE?y/N
054SP-30
TUE, 13 DEC 1988
14:18:26
Flo. 2.44 Radial system indices
purposes, is at the HV connections of the generator transformer and at the HV connections of the station transformer. Variations of voltage and frequency on the grid system are transmitted to the power station electrical systems. Station transformer fed supplies are not protected from step or rapid changes in voltage on the grid system, and their voltage profile closely follows that of the grid. In the longer term, the station transformer tap setting is adjusted manually to regulate the voltage of the systems supplied from it. Supply systems derived from the Unit transformer are shielded from short term grid voltage variations by the action of the generator AVR, which adjusts the generator VAr output to maintain generator terminal voltage at an almost constant value, provided that upper and lower VAr output limits are not exceeded. In the longer term, the generator transformer tap setting may be adjusted to match the generator output to the supergrid/grid voltage, or to contribute to regulating supergrid/grid voltage. 148
The frequency of the whole of the SES is, of course, the same as the grid frequency, neglecting transient effects. It follows from the above that the performance of the grid system is a major influence on the performance of a station electrical system. Adverse voltage regulation due to grid and internal causes cart be additive and influence the choice between installing transformers having on-load tapchangers and transformers having off-load tapchangers within the station electrical system. The SESs are therefore examined with supergrid and grid voltages set to their extremes. This ensures that the tapping ranges on station and generator transformers are adequate.
3.2 Fault level analysis 3.2.1 Introduction
In the event of a fault occurring on a power station electrical system, energy will be released at the point
Power system performance analysis
CIF680 INTERCONNECTED SYSTEM 214 ST -MPSP
ENcowNTER RATE AND DURATION OF TAE OERA1E0 STATES
O.RPTE(0/YEARI
AW.OURfHOURS)
2.0.TImE(N/yEAR3
POWER REDUCTION(/.i
13.27000E 00
0.004SOE
8.16888E Al
100
0.3GSOOE 00
8.12090E 02
0.44280E 01
SO
• . . t,pEcTED LOSS OF ENERGY DUE TO THE uNRELIASILITY OF THE STATION ELECTRICAL AUXILIARY EQUIPMENT • • • 8505.313 MUNO
•
•
•
• mmTINUE?
7,1,
CRASP-38
TOE, 13 DEC 1988
14:59:37
Fro. 2.45 Interconnected system indices
Is
Is
equivalent to
equivalent to
fa}
Ic)
(b)
-EY is
1
equivalent to
I V
/7777-
= *EY
V„
/////
ld
FIG.
(e)
2.46 Replacement of a voltage source by an equivalent current source
149
Chapter 2
Electrical system analysis
GENERATOR D
GENERATOR B
GENERATOR A
0 LINE C-D
LINE B-C
LINE A-B BUS A
BUS
BUS C
BUS B
LOAD D
LOAD B
LOAD A
tal
a
y4
id
ic
ib
Y3
Y2
Y1
7 -1
Y6
Y5
////////////////////
/77
//
(b) Fa. 2.47 A simple power system and equivalent network diagram developed for use in nodal analysis
of the fault. Currents greatly in excess of normal
may flow and considerable damage result. Synchronous machines and induction machines possess kinetic energy and magnetic field energy, and so contribute to the fault current. Both types of machine supply a current which decreases with time. The induction machine current decays to a small value comparatively quickly, because it has no DC supplied field winding. A synchronous machine fault current decreases to a steady state value in roughly 0.5-1.5 s. The steady state value may be about 0.6 x full-load rating of the machine. Precise values of decay time, initial fault current and final fault current depend on the design of the particular machine. Figure 2.70 shows how the fault current of a synchronous machine varies with time. It is essential to detect faults and to isolate faulty equipment, so protection schemes are designed to detect abnormal conditions in the shortest possible time and initiate operation of switchgear to electrically isolate the faulty equipment. The speed of disconnection is important since the extent of damage also depends on the time for which fault current flows. Furthermore, fast fault clearance makes system recovery easier. All switchgear has specified fault current make and break ratings. Electrical supply systems are designed such that the prospective fault current resulting from 150
any postulated fault does not exceed the capability of the circuit-breaker which must clear that fault. Power station electrical systems are so designed that the fault levels are often well below permitted maximums during normal operating modes. Higher fault levels occur when paralleling two normally separate paths, possibly to take plant out of service or, more often, when running up and shutting down main generating plant. Higher fault levels also occur when auxiliary gas turbines or diesel-driven generators are run in parallel with the main system. The usual way to limit three-phase fault current in power station electrical systems at the design stage is to modify transformer reactance. Increasing a transformer reactance reduces the fault levels on the boards it feeds, but at the same time increases voltage regulation (the voltage drop produced by load current) at these boards. The designer must balance these conflicting requirements — low transformer impedance for good system regulation, i.e., low voltage drop, against high transformer impedance to reduce fault current — and produce a satisfactory compromise. There are other ways of reducing fault levels, e.g., auxiliary generator reactances can be increased. On the power station electrical systems considered here, gas-turbine generators and diesel generators may have their reactances increased to some extent, but stability
Power system performance analysis
Read in initial voltages busbar data and form nodal Y matrix
(a) ITER ITERATION NUMBER
I ITER = ITER a NODE OR BUSBAFI IDENTIFICATION NUMBER
0
Y..
(b) FIG. 2.49 Method of accommodating off-nominal transformer tappings by incorporating off-nominal tap representation into the admittance matrix
'1r
BUSBAR i? SLACK .1TP- PV
CALCULATE NETT BUSBAR 0
APPLY ALGORITHM TO GET Vi
BUSBAR PV?
YES
RATIO Vi to. SPECIFIED VALUE
NO
FIG. 2.50 Simple w circuit deduced when off-nominal taps are in phase i = n?
n = NUMBER OF BUSBARS
YES
>YES SOLUTION CONVERGED? NO
-
FIG.
Kt
ITER YES AXIMUM ITERATIONS, ?
2.48 Logic flow diagram for the
Gauss-Seidel method and regulation are adversely affected and must be
taken into account if this is done. Inductors can be used to reduce system fault levels — again stability and regulation must be taken into account. Converter/ inverter supplied motors make no fault current contribution and because of this are a major advantage in containing system fault levels. However, they also generate harmonics, so analysis is needed to show whether the levels produced are acceptable. They have a higher initial cost than ordinary induction motors, but this is offset by high efficiency at part load, so overall lifetime cost analysis is necessary in considering their use.
FIG.
2.51 Alternative method of representing off-nominal transformer taps
3.2.2 Program construction General remarks
Most of a power station electrical system is designed on the basis of complete phase symmetry. In other words, the loads on each phase are the same and the voltages (and currents) are equal in magnitude and 0 0 phase, displaced by 120 and 240 . At lower voltages, there is some unbalance where single phase supplies are provided but at higher voltages, where supplies are almost exclusively to induction motors and other three-phase loads, symmetry can be assumed during normal operation. In analysis terms, this means that knowledge of the voltage and current in one phase implies knowledge of 151
Electrical system analysis
Chapter 2
NETWORK DIAGRAM DRAWING AND MODIFYING
1
32KV
23ICYG
FPH
BHS1
NYC,
CHL
JETTY
IPSASEK 23 Jun 1961 03 31,35
FIG. 2.52 Analysis diagram of a SES in an oil-fired power station
FIG. 2.53 Analysis diagram of a SES in an AGR nuclear power station 152
Lou+. 2.18
Transformer
design characteristics and equivalent taps
, Ratio
Transformer
Rating ( MVA)
432/ 23.5
Generator
800
400/ 132 kV
Supergrid
240
132/ 11.8/ 11.8 kV
Station
90/60/ 60
23.5/ 11.8 kV
Unit
11/ 3.45 kV
i mpedance on rating
16
I mpedance on 100 MVA
Tap range
Equivalent tap value in 'Yu based on System voltages
Number of Steps
Tap step
Maximum
\ Principal
Minimum
+6.67 to -13.35
18
1.2
15.20
8.0
-6.40
0.0808 0.0832
+15 to -5
14
1.43
15.01
-0.72
- 5.01
14.5 H - L 25 L-L
0.037 H-N 0.239 L - N
±10
14
1.33
2.53
-6.78
-16.09
60
14.5
0.278
±7.5
6
2.33
0.21
-6.78
- 1337
Station and unit auxiliary
12.5
10
. 0.874
±10
8
2.39
5.22
-4.35
-13.90
11/ 3.45 kV
Essential auxiliary
10
a
0.874
± 10
8
2.39
5.22
-4.350
-13.90
I ll 3.45 kV
Chlorination plant
8
7
0.95
±10
a
2.39
5.22
-4.35
-13.90
3300/ 433V
TH H & V services Reactor services
2
7.5
4.082
±5
4
2.4
0.64
-4.16
-8.96
1.6
6
4.082
±5
4
2.4
0.64
-4.16
- 8.96
1.0
4.75
5.171
15
4
2.4
0.64
-- 4.16
- 8.96
IS) Turbine services Essential services ('X' and 'Y') 3300/ 433V
Chlorination plant services Admin and workshop services Reactor lighting Reactor services ( M)
3300/ 433V
Turbine lighting
Noie: The system voltages are 400, 132, 23.5, II, 3.3 and 0.415 kV.
Power system performance analysis
0.02
Electrical system analysis
Chapter 2
I LOAD FLOW RESULTS. BUSBAR PU VOLTS & LINE MVA OADING .60K0
3250 235VG 0
1 003
1.10, 08 ,
KV031 ' 030
11091
3 3.501 002
I 044
053l • 059
0319 046
UTS5 1 DSO
SS1A 1 044
C
0T34
1 044
1
WTA 1 042
Ns
HvWS 040
FPH 1 03?
3 3F01 1 043
CWPH TO
BHA 047
&HS 1 047
1 044
.1-1 00 ' 034
1 04?
11 04065 29
FIG, 2.54
JETTY 1 053
CHL 1 342 ,
Jun
"504 09 34 14
Voltage profile of an oil-fired power station electrical system at minimum load
LOAD FLOW RESULTS- BUSBAR PU VOLTS & LINE MV 570
OADING Accow 1.000
23101G 1 000
0 995
02
HYYYS 1 003
02
FPH 0.544
OHS , 015
1400 0 994
CHI. 005
JLTTY 7 013
FA5344045 29 Jun ?maze 29 35
Fro. 2.55 Voltage profile of an oil-fired power station electrical system at maximum load 1 54
Power system performance analysis
LOAD FLOW RESULTS - BUSBAR PU VOLTS & LINE MVA LOADING
2600 ¶ 320
Flo. 2.56 Voltage profile of a network with a 3.3 kV diesel generator supplying an isolated part of a SES
LOAD FLOW RESULTS - BUSBAR FU VOLTS & LINE MVA LOADING
ADE
JOSE 1 I9
1. 012
"
e 411. :744
; 782 161 . ,- 783 1 054 l 055 0 al
GI 781 257 0
1 056
0
965 1 056 .2
786 1_054
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1 040 02
.
78111 9/ 789 97895 053 053
l 054 0. ,
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E
1.017 n
86CY 1 014 0.2
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A3
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, ç
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02
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0
.2
02
• 2607
0.2 • • 011
54 1 05
1 057
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1 5
1 170?
:
0i13, 50
0 0.1).
°.
13_3r,".41. X
87071 1.043 A
70% l 054 0.2/
1P$0060 29 Jun 1959 ■ 616
Flo. 2.57 Voltage profile with turbine and reactor off-load 165
Electrical system analysis
Chapter 2
LOAD FLOW RESULTS
4os
BUSBAR PU VOLTS & LINE MVA LOADING
09
•
133 1 014
7
1 026 NM 39"
.11
SO
..1 5711 1 008 9?
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1
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554
I • •
1.0
03 494060
29
n 1988 1235 50
2.58 Voltage profile with generator off-load and gas circulators at 55 07o full-load
LOAD FLOW RESULTS • BUSBAR PU VOLTS & LINE MVA LOADING 1 0E0
85 0,990
0.877
•
50
to J5A1
84 0.977
3W
J381 0 987
0-869
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45
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10 3
4.0
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2.
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21
G
4,1
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0
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0
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n 0.979 .116 lit 7 7132 1 000
fi 0
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4
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700 7 007 1.0 29 ,2,,n '998 12734:04
FIG. 2.59 Voltage profile with the first II kV starting/standby feedpump being started 156
995
Power system performance analysis
LOAD FLOw RESULTS - BuSBAR PU VOLTS & LINE MVA LOADING AM
1 012
0 977 84 0 977
..1 561 0 392 20
25
05
0075
15. 1
" J1
.0
06
00
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0.6
7150
1 037
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0 3)
094)
l 2
IPSA9914 29.10 198a 17.41 24
Etc. 2.60 Voltage profile with the first 11 kV starting/standby feedpump at speed and full load
, LOAD FLOW RESULTS. BUSBAR pu VOLTS & LINE MVA LOADING 91 003
1M I 009
4.7
27
754.1 l 011
J581 010
I 022
26 5 67
G
1358 1.009
22 12
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3
8.7
0
132 037
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01
91/ 019 •A
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268E 1 OM
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1 032
3 09
0 995
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0 995
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2
704 1 027 0-
0.995
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1.2
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8600 1 013
1 0
09
0700 1 054
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790 027
IP008615 01 Jul 191111 5551.11
Flu. 2,61 Voltage profile with main generator at 40% full load and gas circulators at full load 157
▪ Electrical system analysis
Chapter 2
I LOAD FLOW RESULTS - BUSBAR PU VOLTS & LINE MVA LOADING
• •
83 009
Bt 1 979
7
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12896616 01 .101 .1984 15.52.10
Fla. 2.62 Voltage profile with second 11 kV starting/standby feedpump being started
clo
LOAD FLOW RESULTS- BUSBAR PU VOLTS & LINE MVA LOADING
B1
159 83 ' 009
321 3 5
394 74
J560 I oil
1
26 97
85A 010
ci
22
02
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0.9
0.7
781
782
010
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a
2
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zas
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154E. ' C 113
.1 501 006
9.- J5C , 096
26
ci
8513 0C9
0 939
1 2
7
0
8600 012 0
J609 1.011
13709 8709? 25 1Q09
`Et7CX 03B 09
03
700 1 .326 0
31286908 01 Jo 1946 1593 19
FIG. 2.63 Voltage profile with second 11 kV starting/standby feedpump at speed and full load 158
Power system performance analysis
1 024
708 1 027
06 0.1 6741 1 057
1.0 14634468 01 44 1511411610.50
FIG. 2.64 Voltage profile with the unit at full load
NETWORK DIAGRAM DRAWING AND MODIFYING TYPE '/I 1 IF YOU NEED ANY HELP
J7
Flo. 2.65
Example of computer generated draughting 159
Electrical system analysis
Chapter 2
LINE DATA 1 335-52'07 136-21:2
4:147 3-12 3:177
11552 11332 11312 J2 3.3111311 3.73313 3.33313 3.3531 3.1231 5.3531
535C-2U 252-3-23
232-2-211
01%32 3
0.1 :32
1331
1:31: 1:211 1:531 :3 1:331 1:330 1:532 1:332 1:532
PAGE 1 OF 3 AES:57-73 24527-31:
. 3 .... 1.317113 1,521 3.313I 11331 11 -532 3,3532 :4 3.331 1.33323 3.32325 32 3.3E3 710:3 73513 13231 2324: 4,X31.1 2,511
1 11189 :,03424 3.33614 3.31211 0.39475 3.31203 0.0:133 0.394 1 5 0.01146 0.0:746 3-39475 0.04971 1.00166 2.09516 0.09516 0.29369 0.03972 1.03471 1.03471 1.11079 1.14329 3.31302 1.21756
OPTIONS: REDISPLAY NEXT PAGE
.1342: 3,25152 3.243:3 3.334:1 1 :41:0 3 3 595 0.34313 1.3 3 3 1 6 3.12236 1.44513 1.32514 2.32534 0.89503 0.08645 1.144:59 0.88148 . 0614 0 0.58109 3.04959 4.09126 4.09126 4.23695 5,34695 0.34:75 4.11111 0
SYSTEM BASE MVA=
100.0
HELP RETURN 1206860 01 :ul 1485 :6:22:24
FIG, 2.66 Example of line data entry
INDUCTION MOTOR DATA 1 535250/JD 2251211-143
11331 1133: 1:351 11351 1:311 1511 11531 11332 11312 :5 06 3.10313 3.12315 133:3 3 33113 1,13323 3.33324 :9 3.322 3.322 3.121 1.1E1 3.3E4 5.5E4 :10 .111 J14 J:3
5.401 5.370 .120 7.100 1.493 1
1.480 5.910 ,300 11460 7,001 5.511 11750 1.000 0.350 1.120 0.950 1.100 1.750 1.000 1.050 1.390 1,050 2.950 ,
2,150 1.330 1.150 1.391
OPTIONS: REDISPLAY
31.12-22
PAGE
5166-0
37-3-211
52-X-PU ROT-R-24.1 001-6-PU
92.934 92.994 79.628 19.628 182.220 79.628 162.220 92.494 71.628 182.220 13.628 92.994 131.214 229.520 241.710 229.620 241.110 229.620 131.214 229.620 252.525 214.110 252.525 96.281 252.525 86.297 214.700 252.525 1 9.529 102.220
1.0330 0.3330 0.3546 0.0596 3.1155 3.0596 3.3155 0.0910 0.0596 0.3155 0.0546 0.0930 0.3195 0.5542 0,5886 0.5542 0.5686 2.5592 0.1195 0.9592 0.8499 0.1258 0.4999 0.3486 0.9999 5.1416 0.8259 0.8990 0.0536 0.3155
1.3146 1.8146 1.8504 1.0504 7.7041 1.8504 7.7011 1.8146 1.8504 2.1047 1.8504 1.11146 5.5015 1.6271 11.1344 9,6217 10.1344 4.6277 5.5015 9.5271 12.3045 1.6275 12.3049 3.4515 12.3049 1.4515 7.9275 12.3049 1.0504 7,7047
SYSTEM RASE MVA2
0.1556 1,1558 0.1095 0.1045 0.5014 0.1095 0.5014 0.1558 0.0095 0.5014 0.1395 1.1558 0.2520 0.4413 0.4640 0.4413 1.4640 0.4413 0.2520 0.4413 1.3836
3.6239
1.1836 0.3661 1.0636 0.3661 1.8258 1.0836 3.1095 3.5014
1 OF
1
1
5-OUT-T1 514-IN-21 3-2121-12 361-15- 22
1.3146 1.3146 1.0512 1.0512 7.7043 1.0512 7.7047 1.3146 1.0502 1.1041 1.1512 1.3146 3.8280 10.9916 11.5700 11.4916 11.5100 10.4916 3.8280 10.4916 1.6053 6.2429 7.8053 3.0505 7.8053 3.0505 6.0409
7.8051 1.2512
7,7147
100.0
HELP RETURN 1P51860 01 Jul 1980 16;22,44
FIG. 2.67
160
Example of induction motor data entry
Power system performance analysis
TRANSFORMER DATA 1 TA2-3TA2:
31.75 - 5353 1175 - .53C
1.13
: 71022 4:1
, 2 3 15 , 3 .
4:34'2
1531 '3
MIN-TAP TAP-STEP
-6.43
-2.62 -2.52
1.04 1.04
2.51 2.58
-13.71
2.33
3.21
-4,35 -0.32
1.11
-4.35 -4.36
-4.35 -4.35
:).01
1.353:
-4.35
-4.35
.3.11
11532 11332
3.3532
-4.35 -4.35
0.01 0.21
1 _572 111:32
3.3'2323 1.3T32A
-4.35 -4.35 -4.35
1 1532 3.51331A
22
-4.35
-4.35 -4.35
5.01 0.01
-4.35
5.01 0.11 0.01
14310
-4.36 -4.15
3.13313
74310
-4.15
-4.15
3.3631B 3.3531
064231 FUEL:
-4.16 -4.16
-4.16 -4.16
3.3531 1.3531
AX3L1 3A01
-4.15 -4.16
-4.16
3.3532 1.3532
?HEAT RAN
-4.16 -4.16
3.3532
325602 FUEL; 04012
-4.16
-4.15 -4.16 -4.15
-4.16 -4.16
-4.16 -4.16
114320 161326
-4.16 -4.16
-4.16 -4.16
E3
-4.16
-4.16
3.3532 3.113125 1.312324 3.112720 3.3E3
OPTIONS: RED ISP LAY NEXT PAGE
V-SPEC
? - s2:r7
15.20 1.20 2.33
_1531
33:
MAE - TAP
8.01 -4.4:
-4.35
(
PAGE 1 OF 2
15.20
3.01 0.31
0.01 0.01 1.01 0.7: 0.01 0.01 0.01 0.01 0.01
SYSTEM BASE MVAm
100.0
HELP RETURN 12556514 01 261
1489
6122.56
FIG, 2.68 Example of transformer data entry
ANALYSIS PARAMETERS
PAGE 1 OF 1
5.85E WA
100.0
14VA
0153 FION CONL, ERSENCE ACCURACY HAX:NUM LOAD FLOW ITERATIONS
0.010 25
MVA
SLACK RUSOAR FAULT TIME SYSTEM FRE.TUENCy REFERENCE MACHINE 6V535.0 NAME RETERENCE HACHINE IDENTIFIER 5102Y DTRATIDH TIME 5124311.174 51E0 LENGTH 56153 ANSLE / POLE
53:5' 0:625
400KV 0.100 50.0 40061 1.00 0.010 540
SEC
SEC SEC
DECREES OR POLE PAIRS
3103 555123. MACHINE SPEEDS? R3.114TO311 SYSTEM DATA1 6T5.310:71 20I510U5 1117E01563 21 500121 15052628 VOLTAGES?
0.040
SEC
RAINT.= AVR DATA? 3R0513131 GOVERNOR DATA?
'
OPTIONS: REDISPLAY
SYSTEM BASE MVAm
100.0
I HELP
11
RETURN 1255660 01 Jul 1904 16:23:04
FIG.
,
2.69 Example of analysis parameters 161
Electrical system analysis
Chapter 2
SUB TRANSIENT PERIOD
SLOWLY DECAx;NG TRANSIENT
pERioo
STEADY STATE PERIOD
Xd 7 s
Fin. 2.70 Traosient short-circuit of a synchronous rnachlne — only one phase envelope shown
\, oltage and current in the other two phases. However, when a network has unbalanced loading between phases, or is subject to an electrical fault involving one or two phases only, then phase symmetry is destroyed. Method of symmetrical components
The method of symmetrical components [10] was developed to reduce the complexity of unbalanced fault analysis and is widely used in computer programs. This method represents an unbalanced system of voltages and currents by the superposition of two symmetrical three-phase systems of opposite phase sequence and a zero phase sequence system, i.e., a single-phase alternating system. Three components are defined: Va
Vo
+ V1
Vb
= VO
2
Vc
= Vo + aVi
+ V2
a V1
+ aV2 + a 2 V2
Or
Vo = 1/3 (V,
V I = 1/3 (V, V2
– 1/3
(Va
Vb Vc) aVb + cx 2 V c ) + a 2 Vb +
Vc)
Where
V a , Vb, V, are network voltages in phases a, b, c Vi
positive sequence component voltage V2 = negative sequence component voltage V o – zero sequence component voltage 0 a is a phase rotation of 120 = exp j 2r/3 is a phase rotation of 240 ° = exp j 47r/3 0 (a 3 is a phase rotation of 360 = exp j 27r = 1) ° or 0 a2
Similar equations can be written for network currents. The component V1 is the normal value of the phase voltage for a balanced system with normal phase sequence (a, b, c) and is called the positive phase sequence component of voltage. Component V2 has the opposite 162
phase sequence (a, c, b) — this is indicated by the phase rotation coefficients a and a 2 — and is called the negative phase sequence component of voltage. Component Vo has no phase displacement between phases a, b and c — there are no phase rotation coefficients present — and is called the zero phase sequence component of voltage. The total power in an unbalanced system is the sum of the symmetrical component powers. The reason for the symmetrical component transformation being so useful in analysis is that, for most types of equipment used in power systems, their positive, negative and zero sequence components are independent of each other, or 'decoupled'. This means the associated matrices used during analysis are diagonal and, in consequence, are easily manipulated mathematically. The values of the various sequence component impedances for generators, overhead lines, cables, transformers, and other electrical apparatus can be obtained by test or from analysis. Positive and negative phase sequence component impedances are identical for static apparatus. Zero sequence impedance is associated with earth return paths and may be greater or less than the positive sequence impedance. Driving voltage is only associated with the positive phase sequence component network. It follows that negative and zero sequence component currents can flow only when their networks are connected to the positive phase sequence component network. The connections between the various networks under fault conditions and the associated equations are given on Fig 2.71, This assumes negligible impedance at the point of fault but this is not always so. In practice, fault impedance is sometimes considered in single line to earth faults and this requires an impedance of 3 x fault impedance to be inserted in the zero sequence network. However, design analysis is usually concentrated on worst conditions and this means setting fault impedances to zero. If fault impedance (Zr) is to be taken into account, for single-line to earth faults, 3Zf is inserted in the zero sequence network. For a doubleline to earth fault, the impedance between phases (Zr) is inserted in each phase network and 3Z f in the zero sequence network. For a three-phase to earth fault Z p is inserted in each phase network, 3Z 8 in the zero sequence network (Z 8 is the impedance to ground) and an additional parallel path is introduced having an impedance of (Zf – Z p )/3 (Fig 2,72).
Generator representation Programs are written to calculate generator fault current contribution according to the amount of machine data entered by the analyst. For complete representation of fault current decrement with time, synchronous, transient and subtransient data must be entered. If only one value of machine reactance is entered, the
Power system performance analysis
NETWORK CONNECTIONS UNDER FAULT CONDITIONS NETWORK INTERCONNECTION
FAULT TYPE
ASSOCIATED EQUATIONS
NEGATIVE
ZERO V, 7 V, + V 2 = 0
G
= /2 =
V. = V 2 L-L
+ 12 = 0
•
=0
V, = V 2 = V,
LLG
I, + 1 2 +
Et]
0
V. = V, = 0 =0
V, V 2 = V o 0
Pic. 2.71 Network connections under fault conditions
A suitable basis for calculating a generator fault current is
with Fault Impedance Zp
zi
( En
Zp
3Zg
—
2.72 Three phase to earth with fault impedance
E'
exp — t/T"
Xe
Xd
Xe
X'd
X" = X e
X"d
X
=
-
fault current calculated for the machine will not be dependent.
ti me
—
exp — t/T' +
account is taken of reactance between generator and fault point by making X
Fit
E (r :
lac —
ZP
where X, is equivalent system reactance; Xd, X, X"d are generator synchronous, transient and subtransient 163
Electrical system analysis
Chapter 2
reactances (direct axis); T', T" are transient and subtransient short circuit time constants; and E, E and E" are the generator voltages behind synchronous, transient and subtransient reactances, respectively. Ako, Ydc = (l /X) exp( — t/T) where X n 2(X"d X"q )/(X',L + and T /[w(R, + R e )]
Consider a network with n nodes, the i th node of which the impedance to ground reference is to be found. If a current of I per-unit is injected into the network at node i, then looking at the matrix and two vectors in general terms we have: Y
+ Xe Y
—1
X„ is generator negative sequence impedance, X4' is generator subtransient reactance (quadrature axis) and R a generator stator resistance.
-1
Y
Yli
•
vi
1
Induction motor representation Data for induction motor performance and analysis are frequently in terms of starting and running values of stator and rotor equivalent resistance and reactance. If so, a suitable method of calculating fault current is based on: Yac = (1/X") exp t/T" and Ydc = (1/X") exp trra where T" = X"AoR r
Yn-1 1
1
1
•••
Yin
I
...
Yr -n 1
v,
0
T a = X"/[w(R s + R e )] X'` = X e + X s + XrstXm /(Xrst + Xm)
= system impedance between motor and fault point =. rotor resistance, stator R.,, Rs resistance X„ X m , X„, = stator reactance, magnetising reactance, rotor reactance at start.
and it is seen that
R e + jX,
Alternatively, a method similar to that used for synchronous machines may be used. Evaluation of fault currents and voltages Once the data for the network to be analysed have been assembled, the nodal admittance matrix Y is formed, as described earlier, and we have: YV = I
remembering that, in a system with n nodes,
and
Y is an n x n matrix V is an n x 1 vector I is an n x 1 vector, leading to Y II = V
The impedance to ground reference at any node can be found from Y -1 , the inverse of the admittance matrix. 164
= Y 1T 1 • 0 + 11 =
1
• 0+ ...
1 + ...
.0
1
Similarly, it can be shown that, with the same unit current injected at node i, Vj = Y 1 . Thus the impedance to ground reference at node i is given by element Y j 1 , and the fault currents can be determined by knowledge of the element Y', the voltage at the node prior to the fault Vi, and the type of fault. Further, it can be seen that only one row or column, 11I, of the 1( -1 matrix is required in the calculation the of V .I. The inverses of the admittance matrices for positive, negative and zero sequence networks can be obtained and the fault current calculated. If, for example, the fault is a line to ground fault, the three sequence impedances will be connected in series with the value of the fault resistance (if any) inserted. Let the summed network impedance be Z, having real and imaginary parts of R and jX, and the node voltage V be Vreal + j Vimag • can be Then the positive sequence real current, calculated from: 2 2 'real = pi real X (R + V imag ) X X]/(R + X )
and the positive sequence imaginary current I
iniag
from:
Ii mag = [Vimag X (R — V,-„i) x X]/(R 2 + X2)
Power system performance analysis this example, a single line to ground fault, the and zero sequence currents will equal the poSitive sequence values due to the series connection between the networks. In general, the fault current in each sequence network can be obtained from the solution of the symmetrical components network interconnected according to Table 2.19. Once the fault currents Ifm, if(2) and I1(0) have been obtained, th? phase 'a' voltage under fault conditions for all busb It's can be evaluated by the application of the superposition theorem. For a short-circuit fault on busbar i he 'a' phase fault voltages at busbar j In negative
'rum = Yiicolvti(t) — vrio)] Ini(2) = Y1 J (2) Pi1i(2) — v1;(2) I ri;(0) = Y1.(0) Wfi(o) where
Yij(I), Yij(2)
V
rod
Yii(0) are the sequence admittances
of branch i — j.
are: Vjr(1)
= \Tito
-
YiT( 11) 'LI(I) 1
=0
— Yi1( 2)
Vo(o) = 0
•— Y iT (01 )
Vjf (2)
and
branches can be determined. The fault current in a branch is the product of the branch admittance and the voltage difference between the ends of the branch. For branch i — j, the current flowing in phase 'a' is given by:
1 where Y ) , YFJ (2 ), YJ () are the elements in the it h h row and P column of the inverses of the sequence admittance matrices.
For a transformer branch, the sending end current is evaluated. A correction for tap is then applied to positive and negative sequence currents. The fault voltages for positive, negative and zero sequence networks can then be calculated. Using Thevenin's Theorem, Vi(t) = Vi(P) — Y1j ( 1 ) 1i(1) V1(2) = 0 —
Fault current in network branches
1
42)
= 0 — Y V)) 11(0)
Having established the voltage distribution in the faulted network, the fault currents in the network
where
Vi(p)
is the voltage prior to the fault.
TABLE 2.19 Fault currents for different types of fault
FAULT
L-G
Ito)
If(2)
IRO)
Vi (p) Y) + y:71 ÷y .71 +3Zi • ) 1112) 11(0)
If(1)
IRO
-IRO
0
Vi( p )
L-L
1 YJ ii(1)) +Y.: ) +Z 1
-1 L-L-G
1110) 1
ii(2)
(Y
L-L-L-G
)
1
÷ Y V))
+ y VI) 1
-1 71 Y- ji(2) 1 + Y IL(0) 1
1 1 YT Ii(2) 1 + Y IIMI., 1
0
0
I)
Vi( p )/Y1 ) +
zr
1 where )( ii7.. 1 , Y 1 Y.: ii(0)are the diagonal elements in row and column i of the inverse sequence (1 ) admittance matrices, Z1 is the short-circuit fault impedance, and subscripts (1), (2), (3) denote positive, negative and zero sequence values, respectively.
y d(1) I
= Y iT( 1 ) + 0.5 Zf
1 1 Y ii(2)
= Y + 0.5 Zf
1
Y:ii(0)1
= Y V)) + 0.5 Zf + 3 Zg
and vi( p )
is the. voltage prior to the fault.
165
Electrical system analysis
Chapter 2
Generator and motor fault current contributions
These can be calculated from knowledge of the generator and motor equivalent admittances, the faulted network voltages and the generator and motor current contributions fed to the system prior to the fault. =
Yi(I)G Vf(1) Y(2)6
t't. 2)
Figure 2.74 shows fault levels after operation (a), the first unit/station 11 kV interconnector B5A to B513, closed. The fault levels on the newly interconnected Ii kV boards are now much higher than those in Fig 2.73. Fault levels also rise to a lesser extent at other boards. All fault levels are within switchgear ratings — if this were not so, the switching operation would not be permitted. Figure 2.75 shows fault levels at the next stage in the switching sequence, after the first station transformer 11 kV circuit breaker (J5A1 to B5A) is opened. Comparing this figure with the base case (Fig 2.73), note a moderate increase in fault level at the 11 kV unit board, B5D. This is due to the additional induction motor contribution, via the unit/station 11 kV interconnector, from the station boards. Figures 2.76 and 2.77 show fault levels for the next two stages of switching. Switching the station transformer out of service will not affect fault levels, hence fault levels after stage (e) are the same as after stage (d). Because the Ii kV switchgear has different make and break ratings and the studies show make fault levels greater than 750 MVA, the above sequence is repeated to determine break values. Break values are always less than make values because the fault current from synchronous machines (assuming constant excitation) and induction machines decreases with time. The break value is calculated at the shortest time postfault that the switches can be activated to break the fault current. This depends on the speed of the sensing transducers, relays and the circuit-breaker operating time. An example of a break fault level calculation is shown in Fig 2.78. This is a repeat of the study shown in Fig 2.76, with current decrements from contributing machines taken into account. A value of 0.07 s is used here for the post-fault time interval before the circuitbreakers start to open. Fault levels at 11 kV boards are less than the break switchgear rating, 750 MVA. If the SES is designed to allow 3.3 kV parallel operation, checks must be made to ensure that closing the 3.3 kV interconnector does not raise fault levels to greater than switchgear ratings. Figure 2.79 shows an example of this; starting with the reference Fig 2.73, a 3.3 kV interconnector is added between boards B6AX and B6BX. Because 11 kV board fault levels are all less than 750 MVA, it is not necessary to repeat this study to determine break values. Figure 2.80 shows a 3.3 kV auxiliary diesel generator connected to board B6AY running in parallel with the main system. The associated 3.3 kV boards have fault levels significantly higher than those in reference Fig 2.73, but are less than the switchgear rating of 250 MVA. So far, the examples of fault levels on station electrical systems (Figs 2.73 to 2.80) have shown symmetrical RMS values. These are satisfactory for initial investigations and yield much useful information; however, the DC component is not included and, of course, the values of real interest are the actual peak current -
=
Yi(0)G Vf(0)
where YIG is the value of the generator equivalent admittance. The subject of fault current contribution from loaded synchronous machines is discussed in references fill and [12].
3.2.3 Use of programs The 'Unit at full load' condition provides a convenient base example for fault analysis of a station electrical system. All plant is assumed to be in service and normal running arrangements adopted. Figure 2.73 shows such a study. The system is for an advanced gas-cooled reactor (AGR) nuclear power station. It provides a convenient starting point or reference for further fault studies having different switching arrangements. Switchgear ratings for this station are: At 11 kV
900 MVA make, 750 MVA break
(47.2 kA and 39.4 kA RMS sym)
At 3.3 kV
250 MVA make and break
(43.7 kA RMS sym)
At 415 V
31 MVA make and break
(43.1 kA RMS sym)
On the diagram, 35* are 11 kV boards, B6* are 3.3 kV
boards and B7* are 415 V boards (* = alphanumeric symbol(s)) Figure 2.73 shows that all fault levels are well within switchgear ratings. Suppose now that the 132 kV/11 kV/I1 kV station transformer is to be taken out of service. This transformer has three windings; each of the two 11 kV secondary windings feeds an 11 kV station board. It is shown on Fig 2.73 as three separate transformers bounded by 33, J5A1 and J581. The procedure to take the transformer out of service is: (a) Switch the first unit/station 11 kV interconnector on-load. Check that it picks up load. (b) Open the associated station transformer circuit-breaker.
11 kV
(c) Switch the second unit/station 11 kV interconnector on-load. Check that it picks up load. (d) Open the associated station transformer
11 kV
circuit breaker. -
no load on the station transformer 132 kV circuit-breaker. If so, open it.
(e) Check that there is 166
Power system performance analysis
THREE PHASE FAULT LEVEL (MVA) FOR EACH BUSBAR AT To 10.0mS
J5 , 32
6680 92
2680
.601
.1600
I
2505
0
5 0
9 701 20
MX 20
700
20
tit
19` E1780 20
e7C9 019 , B7DY 20
7- 7- 7- 7-
FIG. 2.73 Example of a SES network used for fault analysis
THREE PHASE FAULT LEVEL (MVA) FOR EACH HUSBAR AT T= 10.0mS
850 9.0
570 J
30E
2699
7E4 20
792 20
0607 '
0671
3571
970'2 20
87863
8600 11
0485 SO
02 25
2798 •9
705 20
( 267:22
$058
.
7413111Y 20
7
-
0.1
'
7
46
J680
8'0780 20
-
8700 20
D?
Era ,' 970x1 20 '2
. DX
F[G. 2.74 Fault levels after the first unit/station 11 kV interconnector is switched on-load
161
Chapter 2
Electrical system analysis
mow
THREE PHASE FAULT LEVEL (MVM FOR EACH HUSSAR AT Tr. 10.0mS 63
2•52
J510
0
•
• ••
.
19427 U'
31.5
25B
,
J50:
D
CO
850 C.
0
.26
0
.31C) 0
,SAE • 2513E
582
0
868 92
2650
2685
2502
250E
860 75
J6 E
0
J506
2502
660
0
1.11. 7192 •9
713 ,
0 0
2682
0702
20
0
0
414 INP:
: ?BS
20
8685 22
8682 95
2681
52
784 20
9782 20
787
9768 29
13792 20
ADS
13702
20
:0
BUOY 0601
2683
1. 2680
AA%
06 6786o 5
2602
‘
8.-..B70Y •9
K
6 • 4 1:4 7Gx
20
re' 170
J602
0
8702 9205.1 ZO .2
7132 20
1506
2506
26136
ADE
212
1..
762
81 2070y
‘1
91
JSBX
3682
'
8600
8600 0G1 960Y 01 91
6685
260
2600
BMX 20
&137B8
15 70 0 87095 12 :9
8 700 20
' (7tcY
Flu.
168
2.76 Fault levels after the second unit/station II kV interconnector is switched on-load
Power system performance analysis
F[0. 2.77 Fault levels after opening the second II kV circuit-breaker on the station transformer
J5DE
ACE
Etc. 2.78 Example of a break fault levet calculation 169
Chapter 2
Electrical system analysis
THREE PHASE FAULT LEVEL (MVA) FOR EACH BUSBAR AT T= 10.0mS0 St 146'
J5•11 1
.56E
250E
J6DE
SE '57
2611X
(•& .. !5 • 876y 22 }
1.
..
1 7
9' 3 Ax 22
8791'1 22
'
al372134
7DX
19
22
FIG. 2.79 Example of fault analysis for a SES designed to allow 3.3 kV parallel operation
THREE PHASE FAULT LEVEL (MVA) FOR EACH BUSBAR AT T. 10.0mS B1 19525 2256
J6.1.1
.59E
JSBE
• J6BX
0
'
'O
-
7
22
/4- 132AX
2
22
-
'
&21213X
7
20
-
..
19" BMX 20
-
7
s
eke7CY
7- 2
FIG. 2.80 Fault analysis of a SES with a 3.3 kV diesel generator connected in parallel
170
Power system performance analysis that the circuit-breaker has to interrupt, and the maximum prospective current, if closed onto earthed equipment. Thus the symmetrical RMS value of current has to be increased by two factors, the DC offset and the relation between AC peak and RMS values which is 2. This was illustrated in Fig 2.70. The DC offset depends on its initial value, determined by the value of the circuit voltage when the fault occurs; subsequently the rate of d-cay of the DC component depends on the relative value; of resistance and reactance between the current sources and the fault. Figure 2.81 is similar to reference Fig 2.73, but peak asymmetric make fault levels are shown at each board. Figure 2.82 shows RMS asymmetric break fault levels at each board. In both Figs 2.81 and 2.82, maximum initial asymmetry is assumed. When a switch interrupts fault current, the process of starting and maintaining arc extinction depends on current zeros occurring when the switch contacts start to open. For current zeros to occur, the peak AC component of current must exceed the DC offset at the post-fault time considered. The X:R ratio of transformers and associated circuits in power station electrical systems is generally low enough to make the DC component decay rapidly; however, problems can occur where components have high X:R ratios. The most likely place to look for this is at the generator circuit-breaker (used in some nuclear stations). Figure
2.83 shows a trace of fault current adjacent to a generator circuit-breaker and illustrates the relationship between DC and AC current components. Values of fault current against time are also taken at various locations in a supply system and are used to confirm that equipment thermal specifications are adequate. Here, the value of interest is the total energy released before fault clearance, assuming pessimistic design fault clearance time. Sometimes phase-to-earth fault current can exceed three-phase fault current. This occurs where the zero sequence impedance of a network is less than the positive and negative sequence impedances. High phaseto-earth fault currents are not expected in power station electrical systems at voltages where earth fault current is deliberately restricted by neutral earthing resistors. Checks can be made of prospective phaseto-earth fault current with the neutral earthing resistor in service, or with the neutral earthing resistor shortcircuited (which might happen through error or flashover). Similar checks can be made at generator voltages, where earthing arrangements use a distribution type transformer. System minimum fault levels are also required for protection setting purposes. These are obtained by reducing grid infeed to its minimum value, disconnecting local generation and disconnecting the induction motors which run only when plant is loaded.
THREE PHASE FAULT LEVEL (MVA) FOR EACH BUSBAR ASYMMETR 0. PEAK VALUE AT T. 10.0 mS NOTE: TRANSFORMER PHASE SHIFTS NOT INCLUDED 9'
33 759
83 5006
114
JSAI
:54E
JSOE
860 ACE 255
786 87B61 .4
lCi
J60E
07C2
8647
VAX
B Y 52071 54 25
70x
F[o. 2.81 The SES of Fig 2.73 showing peak asymmetric make fault levels 171
Electrical system analysis
Chapter 2
RMS VALUE AT T= 7O.OmS
THREE PHASE FAULT LEVEL (MVA) FOR EACH BUSBAR - ASYMMETR NOTE: TRANSFORMER PHASE SHIFTS NOT INCLUDED
•6.1.47
83 2838
•
•
••
2541
6, 3
JV4
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1350 635
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.1 502
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785 34
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Flo. 2.82 The SES of Fig 2.73 showing RMS asymmetric break fault levels
THREE PHASE FAULT AT B4 - WITH MAXIMUM ASYMMETRY IN 'R' PHASE YELLOW PHASE RED PHASE I pu
BLUE PHASE
MO -
T msec
'CO .
0.0 0
2580
2.20 .0
Fio. 2.83 Trace of a generator circuit-breaker fault current illustrating the relationship of DC and AC components
172
Power system performance analysis The impedance values of system components used in fault level studies are biased by applying a negative tolerance during initial stages of design. This allows manufacturing variation and produces analysis for results which are pessimistic, i.e., higher than the expected true values. Once plant is manufactured, impedance values are measured and these measured ,alues without tolerance are entered as program data. A list of data which can be processed in load flow analysis has been given earlier. A list of additional data required for fault level studies is given below:
two transmission circuits and two busbars/demand supply points loaded as in Fig 2.84.
Circuit data Zero sequence resistance Zero sequence reactance 200Mw
Generator data
00.0
Armature resistance
Direct axis synchronous reactance Zero sequence resistance Zero sequence reactance Direct axis transient reactance Direct axis subtransient reactance Direct axis transient open-circuit (or short-circuit) ti me constant Direct axis subtransient open-circuit (or short-circuit) time constant Program run control data System base (MVA) Fault time System frequency 3.3 Stability analysis 3.3.1
Introduction
General
Stability analysis is used to prove that a power system
is able to withstand the effects of credible faults. This means that when faulty equipment has been disconnected from the power system, frequency and voltage will return to near their pre-fault values on the remaining healthy part of the system within a few seconds, and generators, motors and static plant will continue to operate normally (i.e., as prior to the fault). The capability of a power system to withstand the effects of a fault depends on: (a) The severity of the fault, i.e., its type, voltage and
duration. (b) The configuration of the system itself. (C) The robustness (in an electrical sense) of plant
within the system. Items (b) and (c) can be illustrated by considering a basic AC power system consisting of two generators,
FIG. 2.84 Basic AC power system for stability analysis
The results of a load flow calculation on the above system are given in Fig 2.85, and a full list of the load flow analysis results on Fig 2.86. The generator at Bus 2 has to provide 321 MVAr to maintain Bus 2 voltage at 0.99 per-unit. At Bus 1, generator 1 provides the remainder of the system load plus system power losses, in total 608 MW. It also provides 161 MVAr to maintain Bus 1 voltage at 1.02 per-unit. Each line has a loss of 4 MW and 41 MVAr. Bus 2 voltage angle is 11.5 ° behind Bus 1. Suppose one of the transmission circuits is switched out. The system will settle to a new operating state. This is shown in Fig 2.87 and a full list of the load flow analysis results on data sheet Fig 2.88. The system demand remains the same but the results show that the generation requirements have changed significantly. The generator at Bus 2 now has to provide 397 MVAr to maintain Bus 2 voltage at 0.99 per-unit. At Bus 1, generator 1 provides 617 MW and 176 MVAr. The line loss is 17 MW and 173 MVAr. Bus 2 voltage angle is 23.9 ° behind Bus 1. A consumer taking supplies from Bus 1 or Bus 2 would be unaware of the location of the generators supplying his power, or what transmission circuits are in service. He would not know whether he was being supplied from the system shown in Fig 2.85 or from the system shown in Fig 2.87 because, in both cases, his supply voltage and frequency are the same. However, it has already been shown that there are important differences between the two networks. in Fig 2.85, when a transmission line is switched out, the power transfer between Bus 1 and Bus 2 is maintained by the second transmission line. There is an increase in VAr generation on both generators; this is required to maintain the voltage levels at Bus I and Bus 2 at 1.02 per-unit and 0.99 per-unit, respectively, with the increased transmission circuit VAr loss. 173
Electrical system analysis
Chapter 2
LOAD FLOW RESULTS BUSBAR PU VOLTS/ ANGLE & LINE MW / MVAR LOADING
BUS2 190
Fio. 2.85 Results of a load flow calculation on the system in Fig 2.84
FAST 0ETTUPLEG LOAD
eLcw
OUTPUT OF RESULTS
7113 313S NETAGR.A
S3STEg STUDY TITLE:
L:NE POWER FLTWS
FRCM
--
SUSI 31.31
S3ARS-TO 3L82 RES/
- - - - - - - END:NG
MW
204.095 204.335
Esa
WAR
MVA
30.908 311.408
206.348 216.046
- -
NW
RECEIVING ENO - gVA IVAR
200-703 200.003
-13.511 -13.518
200.219 2 79
-LINE Lnss---!WAR MW 4.193 4.033
47.926 40.326
8.195
81.652
0VERLCAlET C:RCUI: SUMMAR!: - - ?GS-8ARS 7Rnm TO
- -RATING ----L3AGING-----9 MVA MVA PER CENT
R.:1RAR TZTAILS 3USEAR
RGSI BI:S2
TYPE
01.11 ?V
MAXIMIIM M.:MATCH
- -VOLTAGE-MAO ANGIE TEG 2.11 1.0210 0.3301
:.005 MW
FIG.
174
0.000 -11.485
-GENERA:00N-ACTIVE AEACT0Vt MW MVAR
- -
LOAD - - REACTIVE MVAR
ACTIVE :914
-14: MATCH - -
ACT1VE
MW
603.191 600.000
160.91.6 321.036
200.000 1000.301
100...000 300.003
0.015
1208.191
480.052
1200.000
403.380
3.002
RZACTIVE
gVAR
0.000
0.000 MVAR
2.86 Full list of load flow analysis results for the system in Fig 2.84
Power system performance analysis
LOAD FLOW RESULTS. BUSBAR PU VOLTS / ANGLE & LINE MW/ MVAR LOADING
R2162 099.3 -239
Flo. 2.87 Results of load flow calculation with one transmission circuit switched out of service
FAST DEC11.2r2ED 1.CAD FLOW
OUTPUT OF RESULTS
237104 7:7LE: 760 3US NETWORX 5 -0.U:-T TITLE: 3"2 70 -672 1L0412 - - SUSSARS FR.CR 70
- - - - SENDING END 244 MVAA 117.400 0.003
SUSI
15.362 0.000
- - - RECEIVING EN MW KVAA
KVA 424.220 0.130
100.102 0.000
-67.272 0.000
KVA 611.143 0.700
- - - - - -LINE LOSS,SW MVAR 11.297 0.000
1 72.314 0.001
: 7.297
172.974
IVE7L0A1ED C:RCUIT SUMMARY
- -
S -20SARS
F30M
I 1 8 ..; 735r,
:a
71PE
- - RATING MVA
--VOLCAGE-
MAO P.0
1 1 -
3 227
I.7.5 ?V
M:0mAICS
--LO91147 WVA ?ER CENT
ANGLE DEO
1.0200 0.3100
0 . 205 -23.944
. 22 5544
--CZNERATION--ACTIVE REACCIVE
MW
MVAR
- - - - - LOAD - - - -NISPATCH - ACTIVE REACTIVE ACTIVE REACTIVE
MMI
mVAR
KW
613.400 600.000
115.712 391.212
41 00.000 1000.200
100.000 331.300
3.107
1211.400
512.914
1200.320
i moon
2.132
MVAR
0.000
222 MVAR
Ft°. 2.88 Full list of load flow analysis results for the modified system '1 75
Electrical system analysis A small increase in watt generation is also required to supply the increased transmission circuit real power loss. The busbar phase angles move further apart but the consumer sees no change. In Fig 2.87, there is only one transmission circuit between Bus 1 and Bus 2. If this is switched out, there is no interconnection between the two buses. At Bus 1, prior to switching out the transmission circuit, generation exceeds demand. Provided governor and automatic voltage regulator action is effective in reducing generator I output to match consumer demand at Bus , 200 MW + 100 MVAr, and maintain voltage and frequency at pre-switching values, consumers' supplies will be unaffected. At Bus 2, only if the generator can produce 1000 MW and 300 MVAr is it possible to continue to supply full consumer demand. For this reason, the system shown in Fig 2.87 is less secure than the system shown in Fig 2.85. This weakness manifests itself in another way. If both systems are subjected to the same disturbance or fault, we find that the stronger system shown in Fig 2.85 has better post-fault recovery characteristics. This is illustrated in Fig 2.89 and Fig 2.90, which show voltage recovery following a three phase fault at Bus I cleared in 0.12 s. Figure 2.89 shows voltage recovery with two transmission circuits in service and Fig 2.90 with one. Note that in the period of time from 0.3 to 0.6 s, the period following fault clearance, voltages in Fig 2.89 are significantly higher than those in Fig 2.90. Figure 2.91 shows the rotor angles of the generators with two transmission circuits in service and Fig 2.92 with one. The oscillations in Fig 2.91 are smaller in magnitude than those in Fig 2.92. Both characteristics point to the system shown in Fig 2.85 as being better able to withstand faults and other system disturbances. We have seen that disturbances, when they occur, affect a power system by changing its voltage levels and voltage angles. Power flows between the synchronous generators, and this usually restores a system to a steady operating state. In a strong stable system, a steady operating state is restored quickly, the synchronous machines initially oscillate about their new stable positions within the power system and their oscillations are rapidly damped out. A weak power system, although initially stable, may be made unstable by a large disturbance. Here, the initial power transfers between the synchronous generators are insufficient to restore a steady operating state. The generators are no longer cohesive in an electrical sense; voltages vary widely and may change rapidly from small to high values. System transients and disturbances The fastest significant disturbances on power systems are caused by switching operations. Travelling voltage waves result: these are reflected from circuit terminations or circuit impedance changes, for example, where a line is connected to a transformer. These super176
Chapter 2 imposed waves may lead to overvoltages. The time for such disturbances is a few milliseconds. Due to their short duration, they do not affect power system stability, except when they cause short-circuits. Short-circuit disturbances usually last up to about 0.15 s and are limited by protection detection and operating time, and by circuit-breaker fault clearance ti me. They result from a variety of causes, such as, the overvoltages described above, human error (e.g., not removing earths from equipment after maintenance), pollution of line insulator surfaces, or mechanical causes (e.g., accidental damage to a buried cable during site excavation). One, two or three phases may be affected and voltage is depressed to some degree throughout the electrical power system. At generator terminals, this reduction in voltage causes an imbalance between power output and input. This is because mechanical power input remains constant until changed by governor action, while the electrical power output (V3 VI cos) changes as V changes and approaches zero as V nears zero. The reduction in voltage also causes a reduction in the transmission capacity of lines because the maximum power transmitted is proportional to the voltage. Further, induction motors may be unable to draw sufficient electrical power input to match their mechanical power output, and slow down. The fault current will probably be high and may cause thermal and mechanical damage to plant. Often related to short-circuit disturbances, but longer in timescale, are disturbances involving mechanical oscillations of synchronous machine rotors. They occur as a result of system faults, being severe when the faulted equipment is not disconnected quickly, and also occur when system switching causes a major redistribution of power flows. If these disturbances are not contained, i.e., the mechanical oscillations are allowed to increase, a major power system breakdown will occur. The power system is referred to as 'unstable'. Generators will poleslip, voltage will fluctuate from zero to high levels, and distance protection operates to disconnect transmission lines. Induction motors within power station electrical systems may be unable to sustain their mechanical loads, leading to substantial loss of generation output. Minimising power system instability Obviously a power system designer seeks to minimise the possibility of power system instability. For this, he requires primarily: • Generators able to provide and absorb substantial synchronising power, i.e., having low transient reactance. • Generators with high inertia. • Power transmission and distribution networks matched to demand requirements. • Fast acting protection and switching to disconnect faulty plant.
Power system performance analysis
TWO BUS NETWORK OUSESAR YOLTAGE
....
.
...............
.
.
.......
...
.
.
0 5
00
1.a
FIG. 2.89 Voltage recovery with two transmission circuits in service
TWO BUS NETWORK GOO
1
BUSBAR YOLTACA
..............
an
05 -
011S 1
0
4
1.0
FIG. 2.90 Voltage recovery with one transmission circuit in service
177
Electrical system analysis
Chapter 2
TWO BUS NETWORK _Graph
1
.
SU ANGLE
'15 —
..
............
...........
....
....
WA-
45—
0
FIG. 2.91 Rotor angles for two generators with two transmission circuits in service
TWO BUS NETWORK _Grip. 1 541 ANGLE
05
1 0
Ho. 2.92 Rotor angles for two generators with one transmission circuit in service 178
... -•••••••
Power system performance analysis • • •
Fast acting generator automatic voltage regulators. Fast acting generator governors and valving. Automatic switching to restore transmission lines after transient faults.
• Automatic load disconnection schemes to back-up the above. Power flows in large systems Basic theory tells us power will only flow along a transmission line when there is a voltage difference between the ends of the line. On AC systems, voltage is measured in both magnitude and phase angle. On the British supergrid and other large power systems the resistance of transmission lines is much less than the reactance. Transformer resistance is also much less than reactance. This means that the difference in phase angle between line ends, not the difference between voltage moduli, is dominant in determining the watt flow on a transmission line. This is illustrated in Fig 2.93. Similarly, the difference in absolute value of voltage between line ends, not the difference between phase angles, is dominant in determining the VAr flow on a transmission line. Suppose a transmission circuit has a nominal X:R ratio of 10:1, and the voltage at the sending end of the circuit (V,) is equal in magnitude to the voltage at the receiving end of the circuit (V,), and V, leads V, by an angle 45 ° . Then the voltage difference between the circuit ends IS V s V r , and the circuit current I, will lag behind the voltage difference by an angle determined by the X:R ratio of the circuit; here, the angle is tan - I 10 =
(a)
84.3 ° . This is shown in Fig 2.93 (a), note the relative positions of vectors V s , I and V i.. Now let the angle 6 be increased by 50%, but the magnitude of V, and V r remain unchanged. This is shown in Fig 2.93 (b). V, - V r increases by nearly 50% and, in consequence, the circuit current I increases by nearly 50%. [ maintains its position between V, and V r ; at the sending end I lags behind V 5 , i.e., power is being exported at a lagging power factor, and at the receiving end of the circuit I is leading V r , i.e., power is being imported at a leading power factor. Now let V, on Fig 2.93 (a) be increased by 5% and (5 remain unchanged (Fig 2.93 (c)). The position of vector V s - V. is now changed and consequently I changes its position too. V, and V both now lead I and it can be seen that increasing V s has changed the VAr flow on the circuit with only a corresponding minor change in watt flow. In practice, the British supergrid voltage is maintained close to 400 kV or 275 kV throughout the network but, when power transfers are high, there will be considerable differences in voltage angles between busbars. A maximum difference of 40 ° between the extremes of the network would not be unusual. 3.3.2 Analytical and programming considerations
General In mathematical terms, power system stability analysis is the progressive solution of sets of non-linear differential equations. The computation requirements are much greater than for load flow or fault analysis, hence efficient solution methods and data input/output routines are very desirable.
(b)
(c)
FIG. 2.93 Criteria determining power flow in large systems 179
Electrical system analysis Consider the basic operation of a turbine-generator. In its steady state, the mechanical power input is balanced by its electrical power output plus losses, and the generator runs at constant synchronous speed. If a difference exists (say the mechanical input exceeds the electrical output plus losses), the surplus energy is used to change the kinetic energy of the turbine-generator rotor, and to overcome damping torque developed in the damper windings of the generator. (Damper windings are fitted to absorb cyclic disturbing torques.) Unless the energy change is very slow, the equations used in the load flow solution can no longer be used. Let the voltage at the terminals of a generator be reduced due to, say, a short-circuit fault on the system. This means the stator currents will change. This current change is much greater than that brought about by a gradual change in voltage. It is computed using the generator transient and subtransient reactances, while the slower changes are computed using the generator synchronous reactance. To compute these changes, assumptions are made that the generator can be represented by EMEs behind synchronous, transient and subtransient reactances. Transient and subtransient time constants are then used to link the reactance effects. Various methods exist to solve the coupled non-linear differential equations. An approach often used, is to linearise the equations over a very small range and to compute the machine voltage angles in this way over a small time increment. This time increment, or step length, can be made as small as required, but obviously an unnecessarily small step length increases the number of calculations, increasing the cost of computation and the time taken. It is vital to predict post-fault rotor swings accurately. The success of this depends on the accuracy of the model used and the accuracy of the data entered into the program. The speed of movement of individual generator rotors relative to each other is usually very small compared with their basic 50 Hz angular velocity. For this reason, static components of the power system (transmission lines, cable circuits and transformers) are modelled with constant 50 Hz characteristics. Some programs are, however, designed to accommodate changes in system frequency by recalculating component parameters, where they are frequency dependent. Machine controllers (governors and AVRs)
There are many types of controller in use. It is not necessary to model controller actions in load flow and most fault level studies because controller action does not influence the solution. For transient stability calculations, it is essential to model the behaviour of machine controllers accurately and include them in the simulation because these controllers have a strong influence in this case. An IEEE committee [13] set up to standardise computer representation of excitation.- systems, produced 180
Chapter 2 reports setting out general representations of the AVRs then in use. Two of these models are reproduced in Figs 2.94 (a) and (b). These models are usually available in transient stability programs and are used extensively. Figure 2.95 shows a simple rate and position limited integrator controller used to simulate automatic voltage regulators. It is used in several analysis programs developed by the CEGB. A composite steam/hydro governor model is shown in Fig 2.96. This simple model is adequate only if the functions it represents are dominant in the timescale considered. Other more complex models are available which simulate boiler/turbine reheat cycles and the associated valving. The data requirements for these more complex models are given later. The analyst will always wish to use a standard model for his analysis if he can. However, because modern controller design varies so much it is often difficult to match the characteristics of a particular controller to those of a standard model. To overcome this, generalised methods of modelling controllers have been developed, both inside and outside the CEGB. The controller under consideration is modelled in termr of its block diagram. It is then used with synchronous machines in transient stability studies. Facilities also exist in some programs to test the controller by itself in open loop simulation. The elements used to form a controller are of two types. The first type, operational elements, contain the integral operator S. and are phase lag, differential lag, lead-lag and quadratic lag. The second type, non-linear elements, include limiters, deadbands, saturation functions, switches, adders, junctions and user defined functions. Inputs to controllers can be taken from any point in the system under consideration but usually are in the form of electrical power, frequency, terminal voltage, a reference (set according to initial conditions) and a constant value. Output from the controller can be fed to any point in the system, but usually is set to mechanical power for a governor and to field voltage for an automatic voltage regulator. Data requirements
The data which can be processed for load flow and fault level analysis have been listed earlier. Additional data which may be processed for transient stability analysis are given below. Some data are essential, e.g., generator inertia, motor inertia: Circuit data Any specified switching operation Generator data Inertia Damping factor Potier reactance Saturation factor Quadrature axis synchronous reactance
Power system performance analysis
V.
I «Tp
E,
or*
INPUT FILTE
Tp
/C
1+Tp
SATURATING EXCITER
REGULATOR AMPLIFIER
_
Kp (1
T, p)
STABILISER AVR mode). IEEE Type 1
E.
INPUT FILTER
V
STABILISER ,
b) AVR model, IEEE Type 2
FEEDBACK GAIN
INPUT FILTER TIME CONSTANT •
✓
•
FORWARD GAIN
T,
FORWARD GAIN TIME CONSTANT
T
FEEDBACK TIME CONSTANT STABILISING FEEDBACK TIME CONSTANT
MAXIMUM REGULATOR VOLTAGE LIMIT
MAXIMUM EXCITER VOLTAGE LIMIT
MINIMUM REGULATOR VOLTAGE LIMIT
MINIMUM EXCITER VOLTAGE LIMIT
EXCITER CONSTANT
V.
MACHINE TERMINAL VOLTAGE
EXCITER TIME CONSTANT
V,
REFERENCE VOLTAGE (AND OTHER VOLTAGE SIGNALS)
EXCITER SATURATION FUNCTION
Er
EXCITER FIELD VOLTAGE
FIG. 2.94 AVR models
181
Electrical system analysis
Chapter 2
K T,,
FORWARD GAIN
E
STEP FACTOR
E
HIGHEST RATE OF RISE OF FIELD VOLTAGE
E,
EXCITER FIELD VOLTAGE
HIGHEST RATE OF FALL OF FIELD VOLTAGE
V,
MACHINE TERMINAL VOLTAGE
COMPOSITE EXCITERGENERATOR LOOP TIME CONSTANT
Vs
REFERENCE VOLTAGE (AND OTHER VOLTAGE SIGNALS1
MAXIMUM EXCITER VOLTAGE LIMIT EXCITER VOLTAGE LIMIT
FIG. 2.95 Simplified block diagram of a rate and position limited integrator
+ Tp
2p —Now + T 1 + T3 p
FLYB A L LS
CONTROL VALVE
1 + T5 p TURBINE POWER LIMITS
STEAM OR HYDRO
MACHINE SPEED SYNCHRONOUS SPEED
(AG
GOVERNOR REGULATION GOVERNOR TIME CONSTANT T,
GOVERNOR CONTROL SYSTEM TIME CONSTANT
T2
GOVERNOR CONTROL SYSTEM TIME CONSTANT
T3
•
GOVERNOR CONTROL SYSTEM TIME CONSTANT MAXIMUM TURBINE POWER POWER SETTING TURBINE TIME CONSTANT (HYDRO)
15
TURBINE TIME CONSTANT
FIG. 2.96 Composite steam/hydro speed governor model
182
Power system performance analysis Quadrature axis transient reactance Quadrature axis subtransient reactance Quadrature axis transient open-circuit time constant Quadrature axis subtransient axis open-circuit time constant Automatic voltage regulator (AVR) data Identification of model used Name of ,usbar controlled by AVR Forward gun Forward time constant Feedback gain Feedback time constant Maximum regulator voltage limit Minimum regulator voltage limit Rate of change of regulator voltage (rising/falling) Input filter time constant Exciter gain Exciter time constant Exciter ceiling voltage Exciter minimum voltage Regulator amplifier time constant Exciter saturation specification Governor and turbine data Speed governor loop regulation Interceptor loop regulation Maximum turbine power Speed at which interceptor valve starts to close Constant relating output of high pressure and other cylinders High pressure throttle valve time constant Interceptor valve time constant Reheater time constant High pressure mains loop pipe time constant High pressure governor valve upper position limit, upper and lower velocity rates Interceptor valve upper position limit, upper and lower velocity rates Boiler/turbine pipework resistance coefficient Ratio of reheater to high pressure cylinder inlet pressure at full load Induction motor data Any specified switching operations Inertia Drop-off to pick-up time delay Lockout time Data to control program runs Study duration time Study step length Swing angle limit 3.3.3 Use of programs System stability following faults
In preparing a stability study the analyst specifies system configuration prior to the postulated fault, type
of fault, duration of fault, and any post-fault switching (e.g., removal of faulted transmission circuits, busbar, transformer, generator). Three-phase-to-earth faults cause more disturbance than phase-to-phase-to-earth, phase-to-phase, or phaseto-earth faults. For this reason they are the type of fault specified most often. The fault duration may be set in accordance with the expected fault clearance time of the faulted equipment — this depends on the operating time of the equipment protection plus associated switchgear operating time, including tolerances, or to a value derived from general design considerations. The shorter the fault duration, the less the power system is disturbed. In practice, fault clearance time is often a critical factor in determining whether a system remains stable in the post fault period. The fault location can be at any point on the system. Usually the locations giving rise to the most severe disturbances are chosen — this is a matter of experience. If deemed credible, simultaneous fault locations can be specified, e.g., a double-circuit transmission line fault. A fault is simulated by specifying a shunt of low impedance to be switched in at, or close to, the chosen fault location, and to remain connected for the duration of the fault. The low impedance shunt is then switched out. At the time of removing the fault (low impedance shunt), other switching necessary to remove the fault from the network is simulated, i.e., switching out the faulted circuit. The stability study is run until the power system is shown to reach a new state of equilibrium, or to become unstable. In practice, values between one and five seconds are generally sufficient. All programs are designed to produce comprehensive data output. This may be in graphical form, or as tabulated data. Usually the change in rotor angles of the synchronous generators, and busbar voltage levels are of prime interest but, within power station electrical systems, the decrease in induction motor speed is also vitally important. This reduction in motor speed can lead to a situation where the voltage at some boards remains depressed and motors continue to run down, although the remainder of the system recovers. This is because induction motors, when running at speeds substantially below normal rating, take a current well in excess of their full load rating. If several motors fed from one transformer lose speed at the same time, the combined increase in current may overload the transformer and be enough to lower motor terminal voltage, such that the motors are unable to draw sufficient power to accelerate back to normal running speed. An example of the graphical output of a stability study following a fault is given in Figs 2.97 to 2.99. The system configuration prior to the fault has been shown earlier in Fig 2.64 but, for analysis purposes, the boiler feed pumps are assumed running. This is 183
Electrical system analysis
Chapter 2
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shown in Fig 2.97. A three-phase-to-earth fault having a duration of 0.2 s, applied at 11 kV board B5A, is simulated. To avoid repetition of the study, the fault is assumed to be cleared without the disconnection of any (faulted) plant. This has the effect of making the post-fault results pessimistic, i.e., 'safe'. The voltages of greatest interest in the analysis of a SES are those at the faulted board, at the busbar supplying the faulted board and at the boards fed from the faulted board. The speeds (or slips) of the induction motors fed from these boards are also important. A plot of voltage against time at these boards is shown in Fig 2.98 and a plot of induction motor slip against time is shown in Fig 2.99. For ease of analysis, the fault is applied 0.1 s after the study start, and removed 0.2 s later. The voltage reductions at the time of the fault and subsequent recovery are typical of electrical supply system behaviour. Induction motor speed change is inversely proportional to drive inertia and will vary accordingly. The tabulated data output for a stability study includes: • Bus bar voltages and phase angles. • Synchronous generator electrical output and mechanical input. • Synchronous generator rotor angle, field current and field voltage. 184
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• Induction motor electrical input, mechanical output, slip and losses. • Governor parameters. • AVR parameters. An example of tabulated data output for the above study is given in Fig 2.100, which gives comprehensive information about the system state at any specified time; in this example, 0.18 s after fault clearance.
Single fed generator systems In the event of a breakdown in grid supplies, power station auxiliaries are sometimes supplied by a standby generator, usually a gas turbine or diesel-driven alternator. At some magnox type nuclear power stations, the gas circulators are fed by an auxiliary steam turbinegenerator running isolated from the grid system. Analysis procedures for these single generator systems are similar to the procedures for multi-generator systems. However, load increments, relative to total generator capacity, are often greater on single generator fed systems than on multi-generator systems. Because of this, frequency deviations from nominal values tend to be greater on single generator fed systems. Depending on the frequency variation, it may be desirable to use a stability program which recalculates
Power system performance analysis
a
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Electrical system analysis
A271? 0,742EA .
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(b) FIG. 2.100 Example of data output for a stability study 186
9
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WI' Power system performance analysis
system component parameters which are Irequency dependent. Examples of the output from a dynamic stability study of an isolated system are shown in Fig 2.101. these
The system modelled has been shown earlier in Fig 2.65; it represents a single steam generator supplying six gas circulators. The postulated fault is a three-phaseto-earth fault at the cable box (J2) of one of the
MOTOR LOADING OF 2.9MW - 0./25S FAULT
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- GENERATOR TERMINAL VOLTAGE (P.U.) GENERATOR TERMINAL CURRENT (P.U. ON RATING) GENERATOR REAL AND REACTIVE TERMINAL POWER (P.U. ON RATING) GENERATOR FREQUENCY (P.U.)
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FIG. 2.101 Example of the output from a dynamic stability study on an isolated system
187
Electrical system analysis
Chapter 2
gas circulators. It is, for analysis purposes, assumed to be of 0.125 s duration and is cleared by opening the associated circuit-breaker at the main board (GC.BD). This is simulated in the analysis by removing the cir-
cuit between GC.BD and J2, 0.125 s after the appli-
cation of the fault. Figure 2.102 is included here to demonstrate the unacceptable effects of slow fault clearance, in this
MOTOR LOADING OF 2 9mw - 0 1255 FAULT
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0 10-
MOTOR LOADING OF 2.9MW 0.18S FAULT
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Flo. 2.102 Unacceptable effects of slow fault clearance 188
5
Power system performance analysis example on a single generator system. The postulated fault is similar to that shown in Fig 2.101, except that its duration is increased from 0.125 s to 0.18 s, and we have an example where this power system has become unstable. Voltage remains depressed in the post-fault period and the remaining induction motors are unable to accelerate to their normal speed. In practice, the system condition simulated here would , not occur - ecause electrical protection is provided to disconnect •he generator in the event of sustained generator overload or sustained system voltage depression. Afotor run up -
The time taken by an induction motor to run-up from standstill to normal running speed can be calculated using transient stability analysis programs. This run-up ti me can be important; for example, when a boiler feed pump fails and the water input to the boiler becomes insufficient to match the boiler steam output. Generating output will need to be reduced unless a standby pump can be substituted quickly for the failed pump to deliver adequate water supplies to the boiler. To simulate induction motor performance over its whole speed range, it is necessary to provide motor resistance and reactance values, both at the normal motor running speed and when the motor is at standstill. These values are not the same. It is also necessary to specify how the mechanical load on the motor varies while the motor is running up; for example, the mechanical load may be assumed to be constant, or to be proportional to the motor speed. Other functions relating motor speed with mechanical load can be defined, as required. The motor start and run-up is simulated by simply specifying one switching operation during the transient stability study, that of switching in the motor. An example from a direct-on-line motor start and runup study is given in Figs 2.103 (a) to (d). Referring to Fig 2.54, one of the boiler feed pump motors connected to 11 kV SB1 is assumed to be shutdown and is redesignated as motor A. One change in tap position on the station transformer is necessary to reduce the 11 kV station board voltage to 1.014 perunit. The resulting system condition is shown in Fig 2.103 (a). The results of most interest to the analyst are:
• The run-up time of the motor. • The effect of the motor on the system, especially by how much board voltages are reduced. • The effects of these voltage reductions on other motors. • The recovery time of voltages at all system levels. The results of the motor run-up study are shown in graphical form in Figs 2.103 (b) and (c). Figure 2.103 (b) shows the voltages at boards which are electrically close to the motor being started and Fig 2.103 (c) shows the motor run-up curve (slip against time) and the slips of other motors which may be affected by the reduced voltage. The figures show this particular motor running up to speed in 10 s and that the other motors are able to continue supplying their mechanical loads while voltages are depressed during the motor run-up periods. It should be remembered that motor run-up times are strongly influenced by the voltage at the motor terminals during run-up. The voltage curves are those expected; after the initial fall in voltage there is a gradual slight recovery as the motor gains speed and takes less reactive power. Finally, there is a sharp rise in voltage as the motor passes its peak torque, and watt and VAr input reduce simultaneously. These results would be considered satisfactory, because voltages remain within design limits and the motor run-up time is acceptable. Detailed system performance data are available throughout the study period. An example is given in Fig 2.103 (d), at 2 s after the motor start. It shows that motor A at 11 kV SB1 has a slip of 60.99% and a power input of 4.33 MW and 33.55 MVAr, with a terminal voltage of 0.843 per-unit at this instant.
3.4 Future developments of electrical analysis programs Further developments of the electrical analysis programs that are currently in hand include the following: • Harmonic analysis of a power system. • Modelling of converter equipment as part of a user defined modelling facility. • Transient recovery voltages.
189
Electrical system analysiS
Chapter 2
LOAD FLOW RESULTS. BUSBAR PU VOLTS & LINE MV OADING
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Power system performance analysis
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5.119 7.161 0.035
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FIELD CURRENT 2.U. 0.988 2.626 3.030
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POWER INPUT ACTIVE REACT!? Z MW WAR
2.540 2.588 2.918 2,919 2.908 -.104 9.805 0.991 0.000 2.999 1.263 0.195
2.633 2.633 3.015 3.015 2.359 4.326 10.066 1.032 0.110 3.081 1.115 3.205
3.531 1.073
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TERM. CURAENT 0. 2. 0.330 0-010 0-015 0-015 1.035 0.471. 0.136 0.313 0.310 0.343 0.018 3.003
TDROCE (1437 LOAD MOTOR 2.6185 2,6185 3.0093 3.0093 2.9401 -.2657 10.0119 1.0099
2.0316 2.6116 2.3041 2.9941 2.1410 3.8511 10.0123 1.0102 3.1237 1.2917 1.1996
0.007 0.325
3.0218 1.2476 3.1496 3.0000 0.5491 1.0401
HUSSAR 111.0391 3.1E01 MX 5511. 231010 HYD
VOLTAGE 0.999 0.844 0.846 0.641 0.901 0.831
0.300
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0.0000
0.2000
3.5209 1-1402
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ANGLE -3.59 -11.39 -12.02 -12.17 -.04 -11.75 -11.44
.
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. ANGLE 2.71 -10.95 -11.74 -12.24 7.10 -12.20
905050 9933553 FOS ATP 7131
MO CHL
vOLTAGE 0.543 0.052 0.837 1.311 0.934 0.838
ANGLE -7.42 -11.51 -12.44 3,09 -12.13 -12.37
FIG. 2.103 (cont'd) Example of motor start and run-up study 191
Electrical system analysis
4 References I
Chapter 2 Analysis: McGraw-Hill: 1971 Ralston: A First Course in Numerical Analysis: McGraw-Hill: 1979
Allan, R. N. and Avouris, N. M.: Users Manual for GRASP2 ( Graphic/Interactive Reliability of Electrical Auxiliary Systems of Power Stations): University of Manchester Institute of Science and Technology: April 1983
Pettofrezzo: Matrices and Transformations: Prentice Hall: 1966 (out of print)
[ 2 1 Allan, R. N. and Billington, R.: Reliability Evaluation of Engineering Systems: Pitmans: 1987
Arrillaga, Arnold and Harker,: Computer Modelling of Electrical Power Systems: John Wiley: 1983
Avouris, N. NI.: Interactive Reliability Analysis of Electrical Auxiliary Systems (PhD Thesis): University of Manchester Institute of Science and Technology: January 1983
Wagner and Evans: Symmetrical Components: McGraw-Hili: 1933 (out of print)
14] Stott, B.: Power System Load Flow (MSc Lecture notes): University of Manchester Instittue of Science and Technology: 1973 [5]
[6]
192
BrameIler, A.: Analysis of Linear Network Systems (MSc Lecture notes): University of Manchester Institute of Science and Technology: 1973 Stagg and El-Abiad: Computer Methods in Power System
Charles Concordia: Synchronous Machines: John Wiley: (out of print) Stevenson: Elements of Power System Analysis: McGraw-Hill: 1982 (out of print) IEEE Report on Computer Representation of Excitation Systems Paper 31TP 67-424: IEEE Summer Power Meeting: Portland, Oregon July 9-14, 1967
CHAPTER 3
Transformers 1.7.3 Processing and dry-out 1.7.4 Final testing 1.7.5 Power frequency overvoitage tests 1.7,6 Impulse tests 1.7,7 Switching-surge tests 1.7.8 Load runs 1.7.9 Short-circuit testing 1.8 Transport, installation and commissioning 1.8.1 Transport 1.8.2 Installation and site erection 1.8.3 Site commissioning
Introduction
1
General design and construction 1.1 Types of transformer 1.1.1 Phase relationships — phasor groups 1.1.2 Star/star connected transformers 1.1.3 The interconnected star connection 1.2 Basic materials 1.2.1 Dielectrics 1.2.2 Basic materials — copper, iron and insulation 1.3 Transformer characteristics 1.3,1 Basic theory 1.3.2 Leakage reactance 1,3.3 Core loss 1.3.4 Load losses 1.4 Transformer construction 1.4.1 Core construction 1.4.2 Transformer windings 1.4,3 Winding conductors 1.4.4 Low voltage windings 1.4.5 Transpositions 1.4.6 Continuously-transposed strip 1.4.7 High voltage windings 1.4.8 Tapping windings 1.4.9 Disposition of windings 1.4.10 Impulse strength 1.4.11 Thermal considerations 1.4.12 Performance under short-circuit 1,5 Tappings and tapchangers 1.5.1 Uses of tapchangers 1.5.2 Impedance variation 1.5.3 Tapchanger mechanisms 1.5.4 Single compartment tapchangers 1 5.5 In-tank tapchangers 1.5.6 Off-circuit tapchangers 1.6 Tanks, connections and auxiliary plant 1.6.1 Transformer tanks 1.6.2 Oil preservation equipment — conservators 1.6.3 Bushing connections 1.6.4 SF6 connections 1.6.5 Cable box connections 1.6.6 Tank-mounted coolers 1.6.7 Separate cooler banks 1.6.8 Water cooling 1.6.9 Cooler control 1.6.10 Layout of transformer compounds 1.7 Quality assurance and testing 1.7.1 Quality assurance (QA) 1.7.2 Tests during manufacture
Introduction The invention of the power transformer in the latter part of the nineteenth century made possible the development of the modern constant voltage AC supply
2
Special design features 2.1 Generator transformers 2.1.1 Required characteristics 2.1.2 General design features 2.1.3 Single-phase generator transformers 2.1.4 Performance and reliability 2.1.5 Economics of operation 2.2 Station transformers 2.2.1 Station transformer characteristics 2.2.2 General design features 2.3 Unit transformers 2.3.1 Unit transformer characteristics 2.3.2 General design features 2.4 Auxiliary transformers 2.4.1 General design features 2.4.2 Auxiliary transformer insulation systems 2.4.3 Design features of dry-type transformers 2.4.4 Special transformers
2.4.5 Foil windings 2.5 Neutral earthing 2.5.1 Generator earthing transformers — basic principles 2.5.2 Generator neutral earthing transformers — general design features 2.5.3 Practical arrangement 2.5.4 Loading resistor 2.5.5 Generator busbar system earthing 2.5.6 Harmonic suppressors 2.6 Series reactors 2.6.1 General design features 2.6.2 Testing of series reactors 2.7 Instrument transformers 2.7.1 Voltage transformers 2.7.2 Generator voltage transformers 2.7,3 Current transformers 2.7.4 Current transformer construction 3
References
system, with power stations often located many miles from the centres of electrical load. Before that, in the early days of public electricity supplies, these were DC systems with the source of generation, of necessity, close to the point of loading. 193
Transformers
Chapter 3
The power transformer, not only permitted the development of large central power stations but, in addition, made a significant contribution to the development of the power station itself. The amount of auxiliary plant needing an electrical supply in a power station is so great that it is necessary to provide an electrical system similar in magnitude and complexity to that of a small town. As a result, there is a need, in a 2000 MW station, for five or possibly six different voltage level systems, requiring 60 or more power transformers to provide the interconnections. These range from the largest, the generator transformer, which steps up the generator output voltage for connection to the transmission system, to the many very much smaller auxiliary transformers which provide supplies at several voltages down to 415 V. In addition, there is an almost countless number of transformers providing supplies at 110 V and lower, for control and instrumentation equipment.
BLUE C
2
1 General design and construction The transformer interconnects and transfers power between systems at different voltages. It does this with very high efficiency, usually 99% or better, and even the imperfection which results from the incomplete magnetic coupling of primary and secondary, i.e., leakage reactance, is a feature which can be used to advantage by the system designer to reduce system fault levels and the consequent rupturing capability of the system switchgear.
(a)
A
2
A
1
1.1 Types of transformer Transformers in power stations are generally threephase and almost invariably double-wound, i.e., they have electrically separate primary and secondary windings. Auto transformers are not used. Since in a power station each three-phase system requires an earth, it is convenient if one of these windings can be star connected and thereby provide a neutral for connecting to earth either solidly or via a fault current limiting resistor. it is also desirable that a three-phase system should have a delta to provide a low impedance path for third harmonic currents in order to eliminate or reduce third harmonic voltages in the waveform. This requirement is most easily met by connecting the other winding in delta. 1.1.1 Phase relationships
—
phasor groups
If a two winding three-phase transformer has one winding star connected and the other in delta, there will be a phase shift produced by the transformer, as can be seen by reference to Fig 3.1. In the example shown in the diagram, this phase shift is 30 ° before twelve o'clock (assuming clockwise rotation) which is referred to as the 'eleven o'clock' position. The 194
(b)
(c)
Fio. 3.1 Winding connections, phasor and polarity diagram
YELLOW
General design and construction and the simplest way of doing this is to utilise a star/ star transformer. Such an arrangement ensures that both 400 and 11 kV systems are provided with a neutral for connection to earth, but fails to meet the requirement that the transformer should have one winding connected in delta in order to eliminate third harmonic voltages. It is possible, and it may indeed be necessary, to provide a delta connected tertiary winding in order to meet this requirement. However, in recent years it has been the practice to dispense with a delta tertiary winding and the advantages and disadvantages of this are discussed more fully in Section 2.2.2 of this chapter.
secondary delta could also have been made by connecting al b2, bi c2 and Ci a2 which would produce ° a 'phase displacement of 30 clockwise to the 'one o'clock' position. It has also been assumed that the primary and secondary windings of the transformer i n Fig 3.1 (b) have been wound in the same sense, so that the induced voltages appear in the same sense. This producPs a transformer with subtractive polarity, since, if the 'me terminals of a corresponding primary and secondar./ phase are connected together, the voltages will subtract, as can be seen in Fig 3.1 (c). If the secondary winding is wound in the opposite sense to the primary, additive polarity will result. The full range of phase relationships available by arying primary and secondary connections can be v found in BS171 (IEC 76)[1].
1.1.3 The interconnected star connection
The interconnected star connection is obtained by subdividing the transformer windings into halves and then interconnecting these between phases. One possible arrangement is shown in Fig 3.3 (a), producing the phasor diagram of Fig 3.3 (b). There is a phase displacement of 30 ° and, by varying the interconnections and sense of the windings, a number of alternatives can be produced. While the interconnected star arrangement has little application on a power station auxiliary system, it is used to provide a neutral for connection to earth on a system which would not otherwise have one, and for details of this application reference should be made to Chapter 11 of this volume dealing with power system protection. The interconnected star arrangement also has an application when it is necessary to introduce diverse phase relationships into the connections of equipment which can produce high levels of harmonics. Its use can assist the reduction of the level of harmonics at the point of common coupling to the system. This will be discussed further in Section 2.4 of this chapter dealing with auxiliary transformers.
1.1.2 Star/star connected transformers
In addition to the considerations discussed above, when selecting the connection necessary for a threephase transformer, it is also necessary to consider the phase displacement of the associated systems. That is, in transforming to a given voltage level the resultant phase displacement must be the same by whatever route the transformation is arrived at. For example, a generator transformer connecting the 400 kV and 23.5 kV systems would probably be connected star/delta, with the 23.5 kV phasor at one o'clock; that is Ydl. The 23.5/11 kV unit transformer would be connected delta/star, with its 11 kV phasor at the eleven o'clock position; that is Dyl 1. This means that the 11 kV system has zero phase shift compared with the 400 kV system. This will be made clearer by reference to Fig 3.2. If, at the same power station, it is also required to install a station transformer stepping down directly from 400 to 11 kV, then that transformer must produce zero phase displacement
400kV
co
400 kV SYSTEM 12 O'CLOCK
GENERATOR TRANSFORMER ,A,./A YNd I
23.5kV SYSTEM 1 O'CLOCK
UNIT TRANSFORMER
A1X Dyn 11
STATION TRANSFORMER
AIX
YN yno
O
11kV SYSTEM 12 O'CLOCK
FIG. 3.2 Phase shifts of' power station auxiliary system
)95
Transformers
Chapter 3
COILS
(a)
thick, which make up the core or magnetic circuit, and copper or, more precisely, hard-drawn high-conductivity copper, from which the windings are formed. In mot transformers, winding turns are insulated by paper supplemented in some cases by enamel, whilst the major insulation, insulating winding from winding and windings from core, is almost entirely paper or cotton-fibre based board or laminated board, with small amounts of wood or wood laminates used where high mechanical strength is demanded. The properties of these basic materials will be dealt with in further detail in the sections dealing with core and windings. 1.3 Transformer characteristics
(b) FIG. 3.3
Interconnected star winding arrangement
For a detailed treatment of basic transformer theory, the reader is referred to a standard text book [2]. However, it is necessary to carry out a brief review of the basic theory in order to obtain an understanding of how the characteristics demanded in power stations affect the design, how these interact with each other and what performance might reasonably be expected from a given transformer design. 1.3.1 Basic theory
1.2 Basic materials 1.2.1 Dielectrics
The majority of transformers installed at power station sites are oil-filled, using a mineral oil which in the UK complies with BS148. This serves the dual purpose of providing insulation and as a cooling medium to conduct away the losses which are produced in the transformer in the form of heat. Mineral oil is, of course, combustible — it has a fire point of 170 ° C — and transformer fires do someti mes occur. It is usual, therefore, to locate these out of doors where a fire is more easily dealt with and consequentially the risks are less. It is necessary to consider the need for segregation from other plant and incorporate measures to restrict the spread of fire. Because of the fire hazard associated with mineral oil, it has been the practice to use designs for smaller auxiliary transformers which do not contain any oil. These may be entirely dry, air insulated; or they may contain non-flammable or reduced flammable liquid; they have the advantage that they may be located inside buildings in close proximity to the associated switchgear. More will be said about this type of transformer in Section 2.4 of this chapter. 1.2.2 Basic materials — copper, iron and insulation
The other basic materials which go to make a transformer are iron, nowadays almost exclusively cold-rolled grain-oriented in the form of laminations 0.28-0.30 mm 196
A transformer usually consists of two coils linking an iron core. An alternating voltage applied to one of these coils produces an alternating flux within the core. This, in turn, induces an alternating voltage within each turn linking the flux, which, in accordance with Lenz's law, has such a polarity as to oppose that flux if current is allowed to flow. This is normally expressed in the form E = - N(dq5/dt) but, for the practical transformer, it can be shown that the voltage induced per turn is E/N =
(3.1)
where is the total flux linking that turn and K is a constant which depends on the supply frequency and the units in which cl) is measured. For a 50 Hz supply, RMS voltage, and total flux measured in Webers, K is equal to 4.44. This expression is a measure of the voltage induced per turn regardless of which winding a particular turn might be associated with. If the transformer had only one winding this induced voltage, or back EMF, would balance the supply voltage and an equilibrium would be established with the 'transformer' taking a very small current, the magnetising current, sufficient to establish flux within the core. Any other winding would thus develop a voltage proportional to the number of turns and, for a two winding transformer, the familiar relationship exists that
General design and construction EINI = E2N2
(3.2)
where Ei and Nt are the voltage and turns, respecril,ely, of the primary winding and E2 and N2 those of the secondary winding. If a current were then allowed to flow in a secondary winding, by connecting some external load, this current would itself produce a flux, the sense of hich woulc be the same as that of the back EMF d it would thus neutralise the back EMF developed an in the primary winding, thereby allowing current to be drawn from the supply applied to the primary ‘vincling. The flux produced by this primary current is such as to balance the neutralising flux created by the secondary current and equilibrium is established once more. Primary and secondary currents are in inverse proportion to the turns ratio, since IiN1 =I2N2. The transformer has thus accomplished the necessary transformation of voltage levels and 'reflects' into the primary circuit those events which occur in the secondary. The transformation is, however, not perfect. Not all the flux produced by the primary winding links with the secondary for example, so that events as seen from the primary are not a total reflection of those occurring on the secondary, i.e., the transformer has leakage reactance. As already mentioned, establishing flux in the core involves the drawing of a magnetising current. Associated with this flux there are hysteresis losses and eddy current losses in the core. When load current flows there are resistive losses and eddy current losses in the windings. There are also eddy current losses in the tank and the core frame. (b) 3 - phase core-type transformer
1.3.2 Leakage reactance •.s explained above, the leakage reactance of a transformer arises from the fact that all the flux produced by one winding does not link with the other winding. As would be expected, therefore, the magnitude of this leakage flux is a function of the geometry and construction of the transformer. Although there are other forms of construction, the majority of transformers and certainly all power station transformers produced in the UK are of the core-type construction, as shown in Figs 3.4 (a) and 3.4 (b), consisting of a central core surrounded by two or more concentric windings. This central wound section is known as the leg, or limb, and the iron circuit is completed by a return section or yoke. Figure 3.4 (c) shows a partsection of a core-type transformer taken axially through the centre of the wound limb and cutting the primary and secondary windings. The principal dimensions are marked in the figure, as follows:
is axial length of windings (assumed the same for primary and secondary) a is the radial spacing between windings
AXIAL1 LENGTH I
mu t b
mit a m it c -- ---
(c) FiG. 3.4
mit = MEAN LENGTH OF TUFIN
Arrangement of windings on single-phase and three-phase cores
b
the radial depth of the winding next to the core
c
the radial depth of the outer winding
If mit is then the mean length of turn of the winding indicated by the appropriate subscript, mltb for the inner winding, mit e for the outer winding and mlta
197
Chapter 3
Transformers Al.I.M.MM•1■■••■=11
for a hypothetical winding occupying the space between inner and outer windings, then the leakage reactance in percent is given by the expression 70){ = KF(3amit a + brratb + cmIt c )/01 (3.3)
0
where K is a constant of value dependent on the system of units used F is equal to the ampere-turns of primary or secondary winding, i.e., MMF per limb
0 is the total flux in the core Equations (3.1), (3.2) and (3.3) determine the basic parameters which fix the design of the transformer. The MMF is related to the MVA rating of the transformer and the total flux, 0, is the product of flux density and core cross-sectional area. Flux density is determined by the choice of core material and the duty of the transformer. The transformer designer can, therefore, select a combination of ig5 and 1 to provide the value of reactance required by the customer. A larger core cross-section, usually referred to as the frame size, and a longer 1 will reduce reactance and, conversely, reducing frame size and winding length will increase reactance. Unfortunately, the designer's task is not quite as simple as that since variation of any of the principal parameters affects the others which will then also affect the reactance. For example, increasing 0 not only reduces reactance, because of its appearance in the denominator of Equation (3.3), but it also reduces the number of turns, as can be seen by reference to Equation (3.1), which will thus reduce reactance still further. The value of I can be used to adjust the reactance since it mainly affects the denominator of Equation (3.3). Nevertheless, if I is reduced, say, to increase reactance, this shortening of the winding length results in an increase in the radial depth (b and c) of each winding, in order that the same number of turns can be accommodated in the shorter axial length of winding. This tends to increase the reactance further. Another means of fine tuning of the reactance is by variation of the winding radial separation, the value 'a' in Equation (3.3). This is more sensitive than changes in b and c since it is multiplied by the factor three, and the designer has more scope to effect changes since the dimension 'a' is purely the dimension of a 'space'. Changes in the value of 'a' also have less knock-on effect although they will, of course, affect `mlt,'. For a given transformer 'a' will have a minimum value, determined by the voltage class of the windings and the insulation necessary between them. In addition, the designer will not wish to artificially increase 'a' by more than a small amount since this is wasteful of space within the core window. It should be noted that since the kVA or MVA factor appears in the numerator of the expression for percent reactance, the value of reactance tends to 198
.1■114•11■
■•
increase as the transformer rating increases. This is of little consequence in most transformers, as almost any required reactance can normally be obtained by appropriate adjustment of the physical dimensions, but it does become very significant for large generator transformers, as permissible limits of dimensions are reached. 1.3.3 Core loss The purpose of a transformer core is to provide a
low reluctance path for the magnetic flux linking primary and secondary windings. In doing so, the core experiences iron losses due to hysteresis and eddy currents flowing within it which, in turn, show themselves as heating of the core material. Hysteresis loss can be reduced by increasing silicon content but, since this also makes the material brittle and hard, there is a practical limit if the material is to remain sufficiently workable to permit reasonably straightforward core manufacture. This limit is about 41/2% silicon for steel produced by the hot rolling process. Orienting the grain structure by cold rolling so that the magnetic domains are uniformly aligned rather than random also reduces hysteresis and, in fact, can produce such an improvement that the silicon content can be reduced whilst still permitting the use of higher flux densities than the non-oriented steel. Reducing the silicon content (a figure of about 3 07o is used for cold rolled steel) also reduces resistivity, so there is a tendency for eddy current loss to be increased. This is countered by a reduction in plate thickness. This is the basis of the development of cold-rolled grain-oriented steel, 0.28 mm thick, which has been current in the UK since the 1950s. Specific loss for cold rolled steel is very dependent OP internal stress and increases sharply for any compressive stress in the material. It is therefore necessary to anneal frequently during the rolling process. In order to prevent fusion between adjacent layers of the coiled strip, it is given a coating of magnesium oxide in the rolling mill. This is usually supplemented by an additional phosphate coating during the final anneal. These coatings also serve as the insulation between laminations to restrict eddy loss in the completed core. As cores get larger, and core plates wider, higher voltages are induced and the duty of the interlaminar insulation becomes more onerous, so that in practice, for cores greater than about 640 mm in diameter, phosphate/magnesia coated plates are usually given an additional coat of insulation, china clay or varnish, by the core manufacturer. This additional insulation also makes good any damage to the phosphate coating brought about by the grinding off of cutting burrs produced when the strip, initially about one metre wide by several hundred metres long, is cut into individual plates perhaps only 300 mm wide by 2-3 m long.
General design and construction For a given grade of material, hysteresis loss (Wh) is proportional to the area of the hysteresis loop, the maximum flux density and the frequency: wh
x weight
k f
Watts
(3.4)
where n varies from about 1.6 to 2.5 depending on the material. Eddy cu. rent loss (W e ) depends on square of frequency arid on the thickness of the steel, so that we
2 k f 2 t 2 (Bir) x weight
Watts
(3.5)
k i , k2 = constants = frequency, Hz = thickness of material, mm maximum flux density, T
= flux density corresponding to the RMS value of the applied voltage.
In the UK, the supply frequency is 50 Hz and the thickness of the material is determined by the steel manufacturer, so the only variables are B,„,, and Bell'. The steel manufacturer normally quotes the specific loss, in W/kg, at a stated working flux density, usually 1.5 tesla, and provides a curve giving specific loss at other flux densities. A typical curve is reproduced in Fig 3.5. Specific loss is obtained by cutting samples of the material 25 mm wide by 250 mm in length along the rolling direction and building these into a square 'core' with overlapped corner joints, called an Epstein Square, and measuring the loss on this. The total loss of a built up core is then theoretically equal to this specific loss value multiplied by the total weight. In practice, the measured loss ex-
2.0
1.5
SPECIFIC TOTAL LOSS. Wikg
B max
Beff
¶ 0
0.5
0.5
1.0
1 5
20
PEAK MAGNETIC FLUX DENSITY, T
FIG. 3.5 Typical specific loss curve for cold-rolled grain-oriented steel (28M4)
199
Chapter 3
Transformers ceeds this figure by 15-25 07o and this is known as the building factor of the core. Its precise value depends on the type of core and the form of construction. More will be said on this subject in Section 1.4.1 of this chapter which deals with core construction. 1.3.4 Load losses The load loss of a transformer is that proportion of the losses generated by the flow of load current and which varies as the square of the load. This falls into three categories: • Resistive loss within the winding copper and leads. • Eddy current loss in the winding copper. • Eddy current loss in the tanks and structural steelwork. Resistive loss can be reduced by dropping the number of winding turns, by increasing the cross-sectional area of the turn conductor, or by a combination of both. Reducing the number of turns requires an increase in 0, i.e., an increase in core cross-section (frame size), which increases iron weight and iron loss. So load loss can be traded against iron loss and vice versa. Increased frame size requires reduced winding length to compensate in Equation (3.3) and thus retain the same impedance, although as already explained there will be a reduction in number of turns (which was the object of the exercise) by way of partial compensation. Reduction of the winding axial length means that the core leg length is reduced, which also offsets the increase in core weight resulting from the increased frame size to some extent. There is thus a band of one or two frame sizes for which the loss variation is not too great, so that optimum frame size can be chosen to satisfy other factors, such as ratio of fixed to load losses or transport height. The paths of eddy currents in winding conductors are complex. The effect of leakage flux within the transformer windings results in the presence of radial and axial flux changes at any given point in space and any moment in time. These induce voltages which cause currents to flow at right angles to the changing fluxes. The magnitude of these currents can be reduced by increasing the resistance of the path through which they flow, and this can be effected by reducing the total cross-sectional area of the winding conductor or by subdividing this conductor into a large number of strands insulated from each other. The former alternative increases the overall winding resistance and thereby the resistive losses. Conversely, if the overall conductor cross-section is increased with the object of reducing resistive losses, one of the results is to increase eddy current losses. This can only be offset by a reduction of strand cross-section and an increase in the total number of strands. It is costly to wind a large number of conductors, in parallel and so a 200
manufacturer will wish to limit the total number of strands in parallel. Also, the extra insulation resulting on the increased number of strands results in a poorer winding space-factor. As explained above, eddy currents in winding conductors are the result of leakage flux, so a reduction in leakage flux results in smaller eddy currents. It can be seen (Fig 3.6) that a tall slim winding produces less leakage flux than a short squat winding. This can be proved by flux plots and is also evident from Equation (3.3) in that the greater the value of 1, the less the leakage reactance, so there is also a minimum acceptable value of 1 if the eddy current losses are to be restricted to a reasonable level. In practice, manufacturers aim to limit eddy current loss to a value about 25 07o of that of the resistive loss. In terms of the total load losses, the stray losses in the transformer tanks and other structural steelwork, such as core frames only constitute a small proportion. However, they can produce significant amounts of heating in areas of the tank surface and, particularly, in heavy-section flanges which, as well as attracting large amounts of leakage flux, tend to have
(a) Leakage flux paths in single phase core
(e) Leakage flux in squat core
FIG. 3.6 Leakage flux paths in tall and squat windings
General design and construction large cross-sectional areas and hence low resistance to the circulation of eddy currents. Local overheating of flanges can cause rapid deterioration of gaskets consequent serious leakage of oil. The oil itself and suffers rapid degradation if it remains in contact with ° metal at temperatures much above 130 C. Even if the overheating is not severe enough to give rise to either of these problems, there is still the hazard faced by operating staff making accidental contact with the erheated tnk surface. For this reason, it is usual ov to specify that the tank temperature should not exceed m above plinth level. A 80 ° C up to a height of 2.8 ° C is usually permitted above temperature of up to I00 this height. The transformer designer may comply with these requirements by careful design of the core and by routing of heavy-current leads within the tank well clear of the sides and of large-section flanges in particular. If these measures are insufficient, then it might be necessary to provide packets of core steel to act as Flux shunts between the source MMF and the tank side. A typical arrangement of flux shunts is shown in Fig 3.7.
FOR PROTECTION AGAINST FLUX FROM WINDINGS
1.4 Transformer construction
FOR PROTECTION FROM FLUX PRODUCED BY HV LINE LEAD
1.4.1 Core construction Laminations are built up to form a limb or leg having as near as possible a circular cross-section (Fig 3.8) in order to obtain optimum use of space within the cylindrical windings. The stepped cross-section approximates to a circular shape depending only on how many different widths of strip a manufacturer is prepared to cut and build. For the smaller cores of power station auxiliary transformers, this can be as few as seven. In the larger station and generator transformers, the number is eleven or more. Theoretically, these fill from just over 9307o to over 95 070, respectively, of the available core circle. In reality, the actual uti-
FIG. 3.7 Arrangement of shunts for leakage flux
lisation is probably slightly less than this since the manufacturer aims to standardise on a range of plate widths to cover all sizes of cores, and will therefore be unlikely to have available widths which would give the ideal cross-section for every size of core. Manufacturers normally denote frame size by quoting the width of the widest plate, starting at about 200 mm for small auxiliary transformers and increasing in 25 mm steps up to about one metre for the largest generator transformers.
Fio. 3.8 Cross-section of core leg
201
Chapter 3
Transformers The cylindrical wound limb forms the common feature for all power station transformer cores. The form of the complete core will be one of the arrangements
shown in Fig 3.9; of these, by far the most common is the three-phase, three-limb core. Since, at all times the phasor sum of the three fluxes produced by a
SINGLE PHASE BOTH L1MBS WOUND
3 PHASE 3 LIMB CORE
SINGLE PHASE CENTRE LIMB ONLY WOUND
3 PHASE 5 LIMB
SINGLE PHASE CRUCIFORM
FIG. 3.9 Typical core forms for single- and three-phase transformers
202
General design and construction balanced three-phase system of voltages is zero, no return limb is necessary in a three-phase core and limbs and yokes can have equal cross-sections. In order to mit the extent to which the flux path cuts across the li grain of the oriented material, corners of laminations 0 are usually cut on a 45 mitre. Plates at these mitred corners must be overlapped so that the flux can transfer to the adjacent face rather than cross the airgap which is directly in its path. The overlaps are formed by alternating different lengths of plates in successive lays (Fig 3.10).
Fin. 3.10 Arrangement of mitred joints in core
The core is built horizontally by stacking laminations, usually two or three per lay, on a jig or stillage. Figure 3.11 shows a large core being built in the manufacturer's works. Clamping frames for top and bottom yoke will be incorporated into this stillage but it must also provide support and rigidity for the li mbs until the core has been lifted into the vertical position for the fitting of the windings. Holes through the laminations of cold-rolled grain-oriented material cause deviations in the flux path and increase losses. Punching of these holes also creates local stress concentrations which increase losses so that, although bolts through punched holes were the standard means of providing clamping for cores built of hot-rolled steel, it is now practice to minimise bolt holes or, if possible, to eliminate them entirely. Bolts securing top and bottom frames will be designed to pass around the yokes rather than through them, as shown in Fig 3.12. Without clamping bolts the legs have no rigidity at all until the windings have been fitted. This fitting requires the removal of the top yoke which will usually have been placed in position during building to provide rigidity and alignment for the core. The legs are normally clamped as tightly as possible by steel bands, which are stripped off, starting from the top of the leg, as the windings are lowered into place. Once in place these windings, which are built onto a hard synthetic resin bonded paper (SRBP) tube, ensure that the leg remains rigid. The top yoke can then be replaced, suitably interlaced into the projecting ends of the leg laminations, followed by the top core frames. Once these have been fitted, together with any tie bars, axial
clamping can be applied to the windings to compress them down to their correct length. These principles will apply to the cores of all the core-type transformers shown in Fig 3.9. Single-phase cores may have windings on both limbs, in which case limbs and yokes will probably have the same crosssectional area. Alternatively these may have one wound central limb, with two, three or four return yokes. The first arrangement tends to result in the lowest iron loss for a given rating but, since the number of windings is doubled, their cost is increased. The use of a number of return yokes, as in the other arrangements, means that the required cross-section can be achieved with a smaller yoke depth, thus reducing the height for
transport. The three-phase equivalent of this is the five-limb core which can be used to reduce the travelling height of a three-phase unit at the expense of iron losses. It should be noted that, provided transport weight and height limitations permit, the yoke depth can be increased to give a greater cross-section, and hence reduced flux density, compared with the legs. This results in a reduction in specific core loss in the yokes which is greater than the proportional increase in yoke weight, hence in a net reduction in total core loss. This is economic if the saving in the cost of the iron loss over the lifetime of the transformer is greater than the cost of the extra material. Before concluding the description of core construction, mention should be made of the subject of core earthing. Any conducting metal parts of a transformer, unless solidly bonded to earth, will acquire a potential in operation which depends on their location relative to the electric field within which they lie. In theory, the designer could insulate them from earthed metal but, in practice, it is easier and more convenient to bond them to earth. However, in adopting this alternative, there are two important requirements: • The bonding must ensure good electrical contact and remain secure throughout the transformer life. • No conducting loops must be formed, otherwise circulating currents will result, creating increased losses and/or localised overheating. Metalwork which becomes inadequately bonded, possibly due to movement from shrinkage or vibration, creates arcing which will cause breakdown of insulation oil and will produce gases which may lead to Buchholz relay operation (see Section 1.6.2 of this chapter), and can thus be very troublesome in service. The core and its framework represent the largest bulk of metalwork requiring to be bonded to earth. On generator transformers, connections to core and frames are individually brought outside the tank via 3.3 kV bushings and are then connected to earth externally. This enables the earth connection to be disconnected during maintenance so that core insulation resistance checks can be carried out. 203
SJ WJ OISUeJI FIG. 3.11
Large core being built (GEC Alslhont)
(see also colour photograph between pp 496 ancl 497)
(see also colour photograph between pp 496 and 497)
General design and construction
FIG. 1.12 Completed core, showing rrante bolts (GEC Alsthom)
Transformers
Chapter 3
1.4.2 Transformer windings In describing the basic principles of a two-winding transformer, it has been assumed that the windings comprise a discrete primary and secondary, each being a cylinder concentric with the wound limb of the core which provides the low reluctance path for the interlinking flux. Whether of single-phase or three-phase construction, the core provides a return flux path and must, therefore, enclose the winding, as shown in Fig 3.13. As well as dictating the size of the transformer in total, the size of the windings thus dictates the size of the window that the core must provide, and hence the dimensions of the core and the iron losses are determined. The designer must aim for as compact a winding arrangement as possible. Militating against this are the needs to provide space for cooling ducts and insulation, and also to obtain as large a copper cross-section as possible in order to minimise load losses.
LV
HV
HV
HEIGHT
WIDTH
CORE WINDOW
Flu. 3.13 Arrangement of windings within core window
some manufacturers attempted some experimental use of aluminium, but its higher resistivity greatly complicates the designer's problems. It necessitates a greater cross-section of conductor and a larger number of cooling ducts; these in turn cause a large increase in winding size, which increases the size of the core. In addition, the increased winding size increases impedance, requiring a further increase in frame size to counteract this (Section 1.3.2 of this chapter) so the iron losses are increased still further, risking a runaway situation. Unlike other areas of power station plant (e.g., cables) it is exceedingly unlikely that aluminium will ever become a serious rival to copper for transformers. Winding conductors are normally rectangular in section (Figs 3.14 and 3.1$). They have a far better winding space factor compared with circular conductors and are used exclusively, except for the very small transformers where both circular conductors and, on occasions, foil windings are used. These will be discussed further in Section 2.4 of this chapter which deals with auxiliary transformers. Winding strands must be insulated from each other within a winding conductor and, of course, each conductor must be insulated from its neighbour. This is achieved by wrapping the strands helically with paper strip, and at least two layers are used, so that the outer layer overlaps the butt joints in the layer below. The edges of the copper strip are radiused in order to assist in paper covering. This also ensures that, where strands are required to cross each other at an angle, there will be less 'scissor action' tending to cut into the insulation. Where conditions demand it, many layers of conductor insulation can be applied and the limit to this is determined by the need to maintain a covered cross-section which can be built up into a stable winding. This demands that, particularly when they are to have a thick covering of insulation, winding conductors should have a fairly flat section, so that each can be stably wound on top of the conductor below. This usually means that the axial dimension of the strand must be at least twice, and preferably two and a half times, the radial dimension. 1.4.4 Low voltage windings
The following sections will aim to describe how to achieve the best compromise between these conflicting objectives in practice. 1.4.3 Winding conductors Before discussing the details of transformer windings further it is necessary to look in some detail at winding conductors. Power station transformers use copper windings almost exclusively and the detailed requirements for them are set down in BS1432 [3]. During the late 1960s, there was a very sharp rise in the price of copper and 206
Although the precise details of the winding arrangements vary according to the rating of the transformer, the general principles remain the same throughout most of the range of power station transformers and it is therefore convenient when describing these windings to consider specific cases. It is also useful to the reader to be able to relate the descriptions given to practical situations. Generally, a power station transformer is rated to match the associated low voltage switchgear. At II kV, 3.3 kV and 415 V, switchgear ratings extend up to about 3000 A. For the low voltage (LV) winding of most transformers, therefore, this is the order of the
General design and construction
CORE LIMB RADIAL DUCTS BETWEEN TURNS
MEM "9111IMIN
EEEEE
ELL RADIAL DUCTS BETWEEN DISCS
LV I WINDING (SINGLE I LAYER 1 HELICAL)
AXIAL DUCTS
EEEEEE
LV TURN 3 LV TURN 2
HV WINDING (CONTINUOUS DISC)
t
LV TURN
ONE TURN OF LV HAS la STRANDS IN PARALLEL
FIG.
3.14 Section of I N and HV windings showing radial and axial cooling ducts
HV
LV
LV COIL
CORE
FIG.
HV HAS 5 TURNS PER MC 2 STRANDS IN PARALLEL PER TURN
3.15 Transverse section of core and windings,
showing axial cooling ducts
current involved. (There are transformers outside this range, of course; for a 600 MVA generator transformer, the LV current is of the order of 15 000 A.) The voltage ratio is usually such that the current m the high voltage (HV) winding is an order of mag-
nitude tower than this, say, up to about 300 A. In most oil-filled transformers, the current density is between about 2 and 4 A/mm 2 , so that the conductor section on the LV winding is of the order of, say, 50 mm x 20 mm and that on the HV winding, say, 12 mm x 8 mm. As explained in Section 1.3.1 of this chapter, the volts per turn in the transformer is dependent on the cross-sectional area of the core or core frame size. The frame size used depends on the rating of the transformer but, since, as the rating increases the voltage class also tends to increase, the volts per turn usually give an LV winding with a hundred or so turns and a HV winding with a thousand or more. In practice, the actual conductor sizes and the numbers of turns used depend on a good many factors and may therefore differ widely from the above values. They are quoted as an indication of the differing problems in designing LV and HV windings. In the former, a small number of turns of a large-section conductor are required; in the other, a very much larger number of turns but of a much more manageable cross-section are involved, and it is these factors which determine the types of windings used. The LV winding is usually positioned nearest to the core, unless the transformer has a tertiary winding (which are normally of lower voltage) in which case the tertiary will occupy this position; 207
Transformers • The LV winding has the lower test voltage and hence is more easily insulated from the earthed core. • Any tappings on the transformer are most likely to be on the HV winding (see below), so that the LV windings will only have leads at the start and finish and these can be easily accommodated at the top and bottom of the leg. The LV winding is normally wound on a tube of insulation material and this is almost invariably of synthetic-resin-bonded paper (SRBP). This material has high mechanical strength and is capable of withstanding the high loading that it experiences during the winding of the large copper-section coils used for LV windings. Electrically, it will probably have sufficient dielectric strength to withstand the relatively modest test voltage applied to the LV winding without any additional insulation. The hundred or so turns of the LV winding are wound in a simple helix, using the tube as a former, so that the total turns occupy the total winding length, although occasionally, for example, if this winding is to be connected in interstar, the turns might be arranged in two helical layers so that two sets of winding ends are accessible at the top and bottom of the leg. Between the winding base tube and the winding conductor, axial insulation-board strips are placed so as to form a duct for the flow of cooling oil. These strips are usually of a dovetail cross-section (Fig 3.15) so that spacers between winding turns can be threaded onto them during the course of the winding. Axial strips are usually a minimum of 8 mm thick and the radial spacers 4 mm. The radial cooling ducts formed by the spacers are arranged to occur between each turn or every two turns, or even, on occasions, subdividing each turn into half-turns. 1.4.5 Transpositions
It has already been explained that the winding conductor of a LV winding having a large copper crosssection, is subdivided into a number of sub-conductors, or strands, to reduce eddy current loss. The eddy currents were said to result from the radial differences in leakage flux between the inside and the outside of the windings. The induced EMFs causing circulation of these eddy currents can best be equalised and the eddy currents reduced if each conductor occupies all possible positions equally in its true length. It is therefore necessary to transpose the winding conductors periodically throughout the length of the winding. There are various methods of forming conductor transpositions, but typically these might be arranged as shown in Fig 3.16. If the winding conductor has, say, eight sub-conductors, then eight transpositions are needed over the winding length. These are carried out by moving the inner conductor sideways from 208
Chapter 3
INNER STRAND MOVES TO OUTSIDE. ALL OTHER STRANDS MOVE DOWN ONE POSITION
F[G. 3.16 Developed section of an eight-strand conductor showing transposition of strands
below the other seven, which then each move radially inwards by an amount equal to their thickness, and finally the displaced inner conductor would be bent outwards to the outer radial level and then moved to the outside of the stack. 1.4.6 Continuously-transposed strip
Even with an arrangement of transpositions of the type described above and using many subconductors, eddy currents in very high current windings cannot be limited in magnitude to, say, 25% of the resistive losses as suggested in Section 1.3.4 of this chapter. In addition, transpositions of the type described above take up a significant amount of space within the winding. As a result, in the early 1950s, manufacturers introduced a type of continuously-transposed conductor. This enables a far greater number of transpositions to be carried out. In fact, as the name suggests, these occur almost continuously in the conductor itself before it is formed into the winding. Although the 'continuous' transpositions result in some loss of space within the conductor group, this amounts to less space within the winding than that required for conventional transpositions, so that there is a net improvement in space factor as well as improved uniformity of ampereconductor distribution. Figure 3.17 shows how the continuously-transposed conductor is made up. It has an odd number of strands flat formation insulated from each other by enamel only and these are in two stacks side by side axially on the erected winding. Transpositions are effected by the top strip of one stack moving over to the adjacent stack as the bottom strip moves over in the opposite direction. The conductor is moved sideways approximately every 50 mm along its length. In addition to the enamel covering on the individual strands, there is a single vertical paper separator between the stacks and the complete conductor is wrapped overall with at least two helical layers of paper in the same manner as a rectangular section conductor. Manufacture of the continuously-
General design and construction 1.4.7 High voltage windings
FIG. 3.17 Continuously transposed conductor
transposed conductor involves considerable mechanical manipulation of the strands in order to form the transpositions and was made possible by the development of enamels which are sufficiently tough and resilient to withstand this. The introduction of continuously-transposed strip has been beneficial to the design of large transformers, which must be capable of carrying large currents, but its use is not without some disadvantages of which the following are most significant: • A stack which might be up to, say, twelve strands high, wrapped overall with paper, tends to behave something like a cart spring in that it becomes very difficult to wind round a cylindrical former. This problem can be limited by the use of such strip only for large diameter windings. It is usual to restrict its use to windings which have a minimum radius of thirty times the radial depth of the covered conductor. • When the covered conductor, which will of necessity have significant depth in the radial dimension, is bent into a circle, the paper covering has a tendency to wrinkle. This feature has been termed 'bagging'. The bagging, or bulging, paper covering can restrict cooling ducts. This problem can be controlled by restricting the bending radius, as described above, and also by the use of an outer layer of paper covering which has a degree of 'stretch' which will contain the bagging. Also an allowance can be made by slightly increasing the size of the ducts.
Mention has already been made of the fact that the high voltage (I-1V) winding might have ten times as many turns as the low voltage (LV) winding, although the conductor size is considerably less. It is desirable that both windings should be as nearly as possible the same axial length and, assuming the LV winding occupied a single layer wound in a simple helix, the HV winding might require ten such layers. A multilayer helical winding of this type would be somewhat lacking in mechanical strength, however, as well as tending to have a high voltage between winding layers. (In a ten layer winding, this would be one-tenth of the line voltage.) [-IV windings are therefore usually wound as 'disc windings'. In a disc winding, the turns are wound radially outwards one on top of the other starting at the surface of the former. If a pair of discs are wound in this way both 'finishes' appear at the outer surface of the respective discs and the crossover between discs takes place at the inside of the discs. A series of discpairs can be wound in this way and then connected together at their ends to form a complete winding. Such an arrangement requires a large number of joints between sections and so has been largely superseded by the 'continuous disc winding'. This has the same configuration when completed as a sectional disc winding but is wound in such a way as to avoid the need for it to be made in separate disc-pairs. When the 'finish' of a disc appears at the outside radius, it is taken down to the mandrel surface using a tapered curved former. From the surface of the mandrel, a disc is then built up by winding radially as previously. When the complete disc has been formed, the tension is taken off the winding conductor, the taper former removed and the turns laid out loosely over the surface of the mandrel. These turns are then reassembled in the reverse order so that the 'start' is the crossover from the adjacent disc and the 'finish' is in the centre at the mandrel surface. The next disc can then be built upwards in the normal way. A section of continuous disc winding is shown in Fig 3.18.
• Because of the large number of strands, joints in continuously-transposed strip become very cumbersome. • A high degree of quality control of the manufacture is necessary to ensure that defects in the enamel insulation of the individual strands or metallic particle inclusions do not cause strand-to-strand faults.
FIG. 3.18 Arrangement of continuous disc winding
209
Transformers The HV winding requires space for cooling-oil flow in the same way as described for the LV winding. This is provided using dovetail strips against the inner face of the discs and radial spacers interlocking with these. Radial cooling ducts may be formed either between disc pairs or between individual discs. 1.4.8 Tapping windings Up to now, it has been assumed that power transformers have simply a primary and secondary winding. However, all power station transformers have some form of tapping arrangement to allow both for variations of the applied voltage and for their own internal regulation. The range of these tappings goes from -±5 07o variation, adjustable only off-circuit on the smallest transformers, to + ion, or more, on the larger transformers, selectable by means of on-load tapchangers. More will be said later about the subject of tappings and tapchangers. However, it is convenient at this stage to describe the tap windings themselves. In power station transformers the tappings are invariably connected in the HV winding. The reasons for this are twofold. First, it is convenient to assume that the purpose of the tappings is to compensate for variations in the applied voltage which, for all transformers except the generator transformer, will be to the HV winding. (The generator transformer is a special case and will be discussed more fully in Section 2 of this chapter.) As the applied voltage increases, more tapping winding turns are added to the 1-1V winding by the tapchanger so that the volts/turn remain constant, as does the LV winding output . voltage. From the transformer design point of view, the important aspect of this is that, since the volts/turn remain constant, so does the flux density. Hence the design flux density can be set at a reasonably high economic level without the danger of the transformer being driven into saturation due to supply voltage excursions. The second reason for locating tappings on the HV side is that, since this winding carries the smaller current, then the physical size of tapping leads is greatly reduced and the tapehanger itself carries less current. Since the tappings are part of the HV winding, frequently these can be arranged simply by bringing out the tapping leads at the appropriate point of the winding. This must, of course, coincide with the outer turn of a disc, but this can usually be arranged without undue difficulty. In the largest transformers, the tappings have to be accommodated in a separate tapping winding, but more will be said about this in Section 2 of this chapter. 1.4.9 Disposition of windings Mention has already been made of the fact that the LV winding is placed next to the core because it has the lower insulation level. It is now necessary to look in further detail at the subject of insulation and in210
Chapter 3 sulation levels and to examine the effects of these on the disposition of the windings. Transformer windings may either be fully insulated or they can have graded insulation. In a fully insulated winding, the entire winding is insulated to the same level, dictated by the voltage to which the entire winding is to be raised on test. Graded insulation allows a more economical approach to be made to the design of the insulation structure of a very high voltage winding. With this system, recognition is made of the fact that such windings will be star-connected and that the star point will be solidly earthed. The insulation of the earthy end of the winding thus need only be designed for a very nominal level. BS171 requires that all windings up 10 66 kV working level should he fully insulated. Above this, which in the UK means 132, 275 and 400 kV, graded insulation is used. Since in UK power station systems there is no voltage class between 23.5 kV (which is treated as a 33 kV system) and 132 kV, then the former is the highest class of power station transformer winding to be fully insulated. Power station transformers therefore either have both LV and 1-1V fully insulated or the LV fully insulated and the HV insulation graded. There are no transformers at power stations (unlike on the grid system) for which both windings can be graded. Figure 3.19 (a) shows the arrangement of a transformer in which both windings are fully insulated. This might be a unit transformer, 23.5/11 kV and perhaps around 40-50 MVA. The LV winding must withstand an applied voltage test which will raise the entire winding to 38 kV above earth. The winding insulation must therefore withstand this voltage between all parts and earthed metalwork, including the core. Along the length of the winding this test voltage appears across the dovetail strips plus the thickness of the SRBP tube. At the ends, these strips and the tube are subjected to surface creepage stress, so that the end-insulation distance to the top and bottom yokes must be somewhat greater. The 23.5 kV HV winding is tested at 70 kV above earth. The radial separation between LV and HV must be large enough to withstand this with, say, a single pressboard wrap with spacing strips inside and outside (Fig 3.19). The end insulation will be subjected to creepage stress and so the distance to the yoke must be somewhat greater than the HV/LV distance. Between the transformer limbs, the HV windings of adjacent phases come into close proximity. To withstand the 70 kV test voltage between phases, it is necessary to have a clearance similar to that between 1-1V/LV windings with, say, a single pressboard barrier in the middle of this distance, as shown in Fig 3.19 (b). The LV winding leads are taken out at the top and bottom of the leg, which means that they must of necessity pass close to the core framework. Since they are
General design and construction
A PHASE Hy WINDING
C PHASE
B PHASE NV WINDING
-
.3 NINCING
END INSULATION r X3 NV LV DISTANCEI tr
PRESSBOARO BARRIER
PHASE TO PHASE INSULATION CLEARANCE
.4 .1 SULATION
Wi Elevaturin of lully nsulated 3p Vase transformer showing Inlerphase
sec!Ien inroug hi one pease sr a aleo transformer showng iocs 0 , or ^ham ,sulation
AI 3: ;;;.3' • I
barrier
L'NE CONNECTION TO COPPER BAR
TERMINAL •N
WINDING CONDUCTORS BRAZED TO COPPER BAR
I
WINDING END CONNECTION
CORE
HV LV INSULATION
LV
HV
a2
RISING CONNECTION TO NEUTRAL TERMINAL
A. thli CLEAT OF INSULATION MATERIAL NEUTRAL STAR BAR
L
rrPical artangernen1 ol LV winding ends
END leiJSLLATrON
10.1 Section or transformer with NV winding having graded insulation
FIG. 3.19 Arrangements of windings and leads for fully insulated and graded insulation
211
Transformers
Chapter 3
at relatively low voltage, it is probable that the necessary clearance can be obtained by bending these away from the core as close to the winding end as possible and by suitably shaping the core frame (Fig 3.19 (c)). The [-IV winding leads also emerge from the top and bottom of the leg but these are taken on the opposite side of the coils from the LV leads. Being at a greater radial distance from the core frame than those of the LV winding, as well as having the relatively modest test voltage of 70 kV, these require little more insulation than those of the LV winding. It is usually convenient to group the tapping sections in the centre of the HV windings. This means that when all the taps are not in circuit, any effective 'gap' in the winding is at the centre, so that the winding remains electromagnetically balanced. More will be said about this aspect below. The tapping leads are thus taken from the face of the HV winding, usually on the same side of the transformer as the LV leads. Figure 3.19 (d) shows the arrangement of a transformer in which the LV winding is fully insulated and the FIV winding has graded insulation. This could be a station transformer, say, 132/11 kV, possibly 60 MVA. If this transformer had a tertiary winding, this too would probably be at 11 kV and would be placed nearest to the core. The test levels would be the same as for the II kV LV winding of the unit transformer and so the insulation arrangement would be similar to that described above. The 11 kV LV winding would be placed over the tertiary and the tertiary to LV gap -
-
would require radial and end insulation of a design si milar to that between tertiary and core. The 132 kV EIV winding is placed outside the LV winding and it is here that advantage is taken of the graded insulation. For 132 kV class graded insulation, the applied voltage test is only 45 kV above earth, although when the overpotential test is carried out 230 kV is induced between the line terminal and earth. Consequently the neutral end needs insulating only to a level similar to that of the LV winding. However, the line end must be insulated for a very much higher voltage. It is logical, therefore, to locate the line end as far as possible from the core and for this reason it is arranged to emerge from a point halfway up the leg. The HV thus has two half-windings in parallel, with the neutrals at the top and bottom and the line ends brought together at the centre. If, with such an arrangement, the 1-IV taps are at the starred neutral end of the winding, the neutral point can thus be conveniently made within the tapchanger and the voltage for which the tapchanger must be insulated is as low as possible. Unfortunately, it is not possible to locate these tapping coils physically in the body of the HV winding since, being at the neutral end, when these were not in circuit there would be a large difference in length between the HV and LV windings. This would greatly increase leakage flux, stray losses and variation of impedance with tap position as well as creating large unbalanced forces on short circuit. It is therefore necessary to place the taps 212
in a separate winding located outside the HV winding. This winding is shorter than the HV and LV windings and split into upper and lower halves, with an unwound area in the middle through which the HV line lead can emerge. The centre of the HV winding must be insulated from the LV winding by an amount capable of withstanding the full HV overpotential test voltage. This requires a radial distance somewhat greater than that in the 23.5/11 kV transformer and the distance is taken up by a series of pressboard wraps interspersed by strips to allow oil circulation and penetration. Alternatively, it is possible that the innermost wrap could be replaced by a SRBP tube which would then provide the base on which to wind the HV winding. The voltage appearing on test between the line end of the HV winding and the neutral-end taps is similar to that between HV and LV winding so it is necessary to place a similar series of wraps between the HV and tapping windings. These wraps must be broken to allow the central HV line lead to emerge; an arrangement of petalling or formed collars is normally used to allow this to take place without reducing the insulation strength (Fig 3.20). 1.4.10 Impulse strength
The previous section examined the disposition of windings as determined by the need to meet the power frequency tests which are applied to the windings. Nowadays it is the practice to apply an impulse test to power station transformers, as well as the dielectric tests at 50 Hz. Impulse testing arose from the need to si mulate the effect on the transformer of steep-fronted waves of the kind resulting from lightning strikes on the connecting transmission lines: these were of much greater voltage than the power frequency tests but also of very much shorter duration. The standard impulse wave defined in BS171 and specified by the CEGB for power station transformers has a wavefront time of 1.2 /Ls and a time to decay to half peak of 50 As (these times will be more fully defined in Section 1.7.6 of this chapter which deals with impulse testing of transformers). When struck by such a steep wavefront, a transformer winding does not behave as an electromagnetic impedance, as it would to power frequency voltages, but as a string of capacitors. Each turn has a capacitance to the succeeding turn C s and a capacitance to earth C g (Fig 3.21 (a)). It is a fairly simple matter to show that when a high voltage is applied to such a string, the distribution of this voltage is given by a curve of the type shown in Fig 3.21 (b) and the initial slope of the curve, which represents the voltage gradient at the point of application, is proportional to the ratio C g /C s . In a winding in which no special measures had been taken to reduce this voltage gradient, this would be many times that which would appear under power, frequency conditions. If additional insulation were• placed between the winding turns, this
General design and construction
a
LV
CORE
2
LV
'-I V
al
FIG. 3.20
A2
Arrangement of HV line lead with outer HV tapping winding
would increase the spacing between them and thus reduce the series capacitance C s . C g would be effectively unchanged, so that the ratio C g /C, would increase and the voltage gradient become greater still. The most effective method of controlling the increased stress at the line end is clearly to increase the series capacitance of the winding, since reducing the capacitance to earth is not very practicable*. Figure 3.22 shows several methods by which the series capacitance can be increased. The first (Fig 3.22 (a)) uses an electrostatic shield connected to the line end and inserted between the two HV discs nearest to the line end. The second (Fig 3.22 (b)) winds in a dummy strand connected to the line lead but terminating in the first disc. Both of these arrangements effectively bring more of the winding turns closer physically to the line end. Thirdly, a system of interleaving (Fig 3.22 (c)) can be used, whereby the winding turns can be taken from the line end further into the body of the winding rather than simply winding in series. This usually involves winding two or more strands in parallel and then reconnecting the ends after winding to give the interleaving arrangement required. It has the advantage over the first two methods that it does not waste any space, since every turn remains active. However, the cost of winding is greatly increased by the large number of joints. It is possible by adjustment of the degree of interleaving, to achieve a nearly linear distribution of impulse voltage through'Footnote: A short squat winding tends to have a lower capacitance to ground than a tall slim winding, so such an arrangement would have a better intrinsic impulse strength. There are, however, so many other constraints tending to dictate winding geometry that manufacturers are seldom able to use this as a practical means of obtaining the required impulse strength.
out the winding. In view of the high cost of interleaving, the designer aims to minimise this and, where possible, to restrict it to the end sections of the winding. A further problem can occur at the neutral end of the winding, since it is possible for reflections of the impulse wave to be produced which can give rise to oscillatory conditions which, depending on their magnitude and phase relationships, can produce comparable stresses to those which occur at the line end. In addition, if some of the tapping winding is not in circuit, which happens whenever the transformer is on other than maximum tap, the tapping winding will then have an overhang which can experience a high voltage at its remote end. The magnitude of the impulse voltage appearing both across the neutral end sections and within the tapping winding overhang will be at a minimum when the initial distribution is linear, as can be seen from Fig 3.21 (c), and this is usually assisted by a further interleaved section at the neutral end. To some extent, the magnitude of the impulse voltage seen by the tapping winding due to overhang effects is dependent on the size of the tapping range, so this must be borne in mind when deciding the tapping range required. 1,4.11 Thermal considerations
When the resistive and other losses are generated in the transformer windings heat is produced. This heat must be transferred into, and taken away by, the transformer oil. The winding copper retains its mechanical strength up to several hundred degrees Celsius. Trans° former oil does not degrade below about 140 C, but paper insulation deteriorates with greatly increasing 213
Transformers
Chapter 3
I
I
(a) Electrostatic shield
111111•1111111•1111 •••11•111•••• •11••••••••
(a)
ot,
LINE END
(b) Dummy Strand E]
DISTANCE FROM LINE LEAD (n)
OSCILLATION FOLLOWING INITIAL DISTRIBUTION INITIAL DISTRIBUTION
111 •11•11• II • • • J11 M, 11 MI 11 MI 11 11 11 • IN (b) Interleaving of 2 strands over 4 discs FIG. 3.22 Types
-4—
OVERHANG
FIG. 3.21 Distribution of impulse voltage within winding
rapidity if its temperature rises above about 90 ° C. The cooling-oil flow, therefore, must ensure that insulation temperature is kept below this figure as far as possible. The temperature at which no deterioration of paper insulation occurs is about 80 ° C. It is usually not economic or practical, however, to limit the insulation temperature to this level at all times. Insulation life would greatly exceed transformer design life and, since ambient temperatures and applied loads vary, a maximum temperature of 80 ° C would mean that on many occasions the insulation would be much cooler than this. Thus, the critical factor in determining the life of a transformer is the working temperature of the insulation or, more precisely, the temperature of the hottest part of the insulation or/tot spot. The problem 214
of winding stress control
is to decide what temperature the hot spot should be allowed to reach. Various researchers have considered this problem and all of them tend to agree that the rate of deterioration or ageing of paper rapidly increases with increasing temperature. In 1930, Montsinger [4] suggested that the life of insulation would be halved for every 8 ° C increase between 90 and 110 ° C and this rate has been generally accepted, although some authorities now consider that a value of 6 ° C is more appropriate for present-day insulation materials. It must be recognised that there is no generally accepted temperature at which insulation may be allowed to operate, nor is there agreement between transformer designers as to the precise hot spot temperature that should be accepted in normal operation. In fact, it is now recognised that there are other factors affecting insulation life, such as the moisture content, acidity and oxygen content of the oil, all of which tend to be dependent upon the system of breathing employed. Nevertheless BS171 and other international specifica-
General design and construction
dons set down limits for permissible temperature rise which aim at a life of about thirty years for the transformer. Such documents assume that a lifetime of this magnitude would be obtained with a hot spot ° temperature of about 98 C. It must also be recognised that the specified temperature rise can only be that value which can be measured, and that there will usually be, within the transformer. a hot spot which is hotter than the temperature tha can be measured and which will really determine the life of the transformer. Study of Cie permitted temperature rises given in BS171 shows that a number of different values are permitted and that these are dependent on the method of oil circulation. The reason for this is that the likely difference between the value that can be measured and the hot spot, which cannot be measured, tends to vary according to the method of oil circulation. Those listed in BS171 are:
1111111-1111 1111111 111111111= • 111 11 • 111 1•1111 111 111
111111 1111111 111111 E (a) Non-directed flow
• Natural. • Forced, but non-directed. • Forced and directed. Natural circulation utilises the thermal head produced by the heating of the oil which rises through the windings as it is heated and falls as it is cooled in passing through the radiators. With forced circulation, oil is pumped from the radiators and admitted to the bottom of the windings to pass through the vertical ducts formed by the strips laid 'above' and 'below' the conductors. In referring to axial ducts within windings, the expressions 'below' and 'above' mean 'nearer to the core' and 'further from the core', than the winding turns respectively. Radial ducts are those which connect these. In a non-directed design, flow through the horizontal ducts which connect the axial ducts above and below is dependent entirely on thermal and turbulence effects and the rate of flow through these is very much less than in the axial ducts (Fig 3.23 (a)). With a forced and directed circulation, oil flow washers are inserted into the windings which alternately close off the axial ducts above and below the conductors, so that the oil in passing through the winding must also weave its way through the horizontal ducts. This arrangement is illustrated in Fig 3.23 (b). The average temperature rise of the winding is measured by its change in resistance compared with that at a known ambient temperature. Since some of the winding at the bottom of the leg is in cool oil and some at the top is in the hottest oil, there will be a difference from the average at either extreme by an amount equal to half the difference in temperature of the inlet and outlet oil. In addition all the conductors may not be equally exposed to the oil. In the diagram of Fig 3.24, which represents a group of conductors surrounded by vertical and horizontal cooling ducts, the four conductors at the corners are cooled directly
411 11111111111111111 (c) Directed flow Flo. 3.23 Directed and non-directed oil flow
on two faces, whilst the remainder are cooled only on one. Further, unless the oil flow is forced and directed, not only will the heat transfer via the horizontal surfaces be poorer, due to the poor oil flow-rate, but this oil could well be hotter than the general mass of oil in the vertical ducts. The temperature of the winding hot spot is thus the sum of the following: • Ambient. • Measured (specified) rise by resistance. • Half difference between inlet and outlet oil. • Difference between average and maximum winding/ oil temperature gradient. 215
1P, Transformers
Chapter 3
CONDUCTOR COOLED ON ONE SURFACE
HORIZONTAL COOLING DUCTS
CONDUCTOR COOLED ON 2 SURFACES
VERTICAL COOLING DUCTS FIG. 3.24 Winding hot spots
1.4.12 Performance under short circuit -
Typical values are: Type of cooling
(a) Ambient (BS171) (b) Rise by resistance (BS171) (c) Half (outlet-inlet) oil (d) Maximum gradient — average gradient
OFAF Forced 8c directed oil flow
ONAN Natural nondirected oil
30 70
8
30 65 12
2
3
110
110
It must be stressed that since items (c) and (d) cannot be covered by specification, they are typical values only and actual values will differ between manufacturers and so, therefore, will the value of hot spot temperature. It will be noted also, that the hot spot temperatures derived significantly exceed the figure of 98 ° C quoted above as being the temperature which corresponds to normal ageing. It will also be seen that the figure used for ambient temperature is not the maximum recognised in BS171, which permits an ambient temperature of 40 ° C, giving a hot spot temperature of 120°C. Such temperatures are permissible because the maximum ambient temperature occurs only occasionally and for a short time. When a transformer is operated at a hot spot temperature above that which produces normal ageing due to increase either in ambient or loading, then insulation life is used up at an increased rate. This must then be offset by a period with a hot spot temperature at or below that for normal ageing, so that the total use of life over this period equates to the norm. This is best illustrated by an example: if two hours are spent at a temperature which produces twice the normal rate of ageing then four hours of life are used in this period. For the balance of those four hours (i.e., 4 — 2.2) the hot spot temperature must be such as to use up no life, i.e., below 80 ° C, so that in total four hours of life are used up. Jlhjs principle is fully 216
explained in BS Code of Practice CP 1010 [5], which deals with the subject of loading of power transformers. The system works well in practice since very few transformers are operated continuously at rated load. Even in power stations where loads tend to be more constant than for many other applications, loads vary as the unit load is varied or as the unit is started up and shut down, and ambient temperatures vary seasonally. There is one exception to this loading pattern. This is the generator transformer of a large base-load unit. Ideally, this operates at near to its designed rating continuously, apart from its periodic maintenance shutdown. This will be discussed further in Section 2 of this chapter dealing with the subject of generator transformers.
The effects of short-circuit currents on transformers, as on most other items of electrical plant, fall into two categories: • Thermal. • Mechanical forces. It is a fairly simple matter to deal with the thermal effects of a short-circuit. This is deemed to persist for a known period of time, usually 3 or 5 s, allowing for clearance of the fault by back-up protection. During this brief time, it is safe to assume that all the heat generated remains in the copper. Therefore knowing the mass of the copper, its initial temperature, and the heat input, the temperature which it can reach can be easily calculated. It simply remains to ensure that this is below a permitted maximum which for oilimmersed windings is taken to be 250 ° C, in accordance with Table III of BS171: Part 5: 1978. Mechanical short-circuit forces are more complex. First, there is a radial force which is a mutual repulsion between LV and HV windings. This tends to crush the LV winding inwards and burst the HV winding outwards. Resisting the crushing of the LV winding is relatively easy since the core lies immediately beneath and it is only necessary to ensure that there is ample support, in the form of the number and width of axial strips, to transmit the force to the core. The outwards bursting force on the HV winding is resisted by the tension in the copper, coupled with the friction force produced by the large number of HV turns which resists their slackening off. This is usually known as the 'capstan effect'. Since the tensile strength of the copper is quite adequate in these circumstances, the outward bursting force on the HV winding does not normally represent a problem either. An exception is any outer winding having a small number of turns, particularly if these are wound in a simple helix. This can be the case with an outer tapping winding or sometimes the HV winding of a unit transformer which,
General design and construction having a voltage very little higher than that of the LV, might well be a helical winding (Section 1.4.4 of his 'chapter). In these situations, it is important to t ensure that adequate measures are taken to resist the outward bursting forces under short-circuit. These might involve fitting a tube of insulation material over the winding or simply securing the ends by means of taping, not forgetting the ends of tapping sections, if included. An )ther alternative is to provide 'keeper sticks' over the surface of the coil which are threaded through the interturn spacers. Such an arrangement is shown in Fig 3.25 in which keeper sticks are used over the helical winding of a large reactor. Secondly, there is also usually a very substantial axial force under short-circuit; this has two components. The first results from the fact that two conductors running in parallel and carrying current in the same direction are drawn together, producing a compressive force. Alternatively, as will be seen by reference to Fig 3.26 (a), it may be seen as an effect of the radial component of the
leakage flux which will be in one direction at the top of the leg and the other direction at the bottom. Since the current is in the same direction at both top and bottom it produces a force in opposite directions which is, in fact, compressive. The second component of axial force is due to magnetic unbalance between primary and secondary windings, i.e., the axial displacement between their magnetic centres (Fig 3.26 (b)). In very large transformers, the designer aims to achieve as close a balance as possible between the windings, but this cannot be achieved entirely for a number of reasons. One is the problem of tappings. Putting these in a separate layer so that there are no gaps left in the main body of the HV winding when taps are not in circuit, helps to some extent. However, there will be some unbalance unless each tap occupies the full winding length in the separate layer. One way of doing this would be to use a multistart helical tapping-winding but, as mentioned above, simple helical windings placed outside the EIV winding would be very difficult
FIG. 3.25 Part of a Winding of a saturated reactor showing detail of external bracing (GEC Alsthom) 217
Transformers
Chapter 3
RADIAL COMPONENT OF LEAKAGE FLUX FORCES ON CONDUCTORS CURRENT (INTO PAPER) PATH OF LEAKAGE FLUX
(a) 1
SMALL RADIAL COMPONENT OF FLUX I
tF
1 F2
>
F HENCE NET UPWARD 1
FORCE ON OUTER WINDING IF
PATHOF LEAKAGE FLUX
(b)
..
. LARGE RADIAL COMPONENT OF LEAKAGE FLUX
FIG. 3.26 Forces within windings
to brace against the outward bursting forces. In addition, spreading the tapping turns throughout the full length of the layer would create problems in taking the HV line-lead away from the centre of the winding. Another factor which makes it difficult to obtain complete magnetic balance is the dimensional accuracy and stability of the materials used. Paper insulation and pressboard in a large winding shrink axially by several centimetres during dry-out and assembly of the windings. Although the manufacturer can assess the degree of shrinkage expected fairly accurately, and will attempt to ensure that it is evenly distributed, it is difficult to do this with sufficient precision to ensure complete balance. Furthermore, shrinkage of insulation continues to occur in service and, although the design of the transformer should ensure that the windings remain in compression, it is even more difficult to ensure that such shrinkage will be uniform. With careful design the degree of unbalance will be small. Nevertheless it must be remembered that short-circuit forces are proportional to (current) 2 and that the current in question is the peak asymmetrical current and not the RMS value. Consequently, for a generator transformer, having an impedance of 16%, the magnitude of the force might be 116 times that occurring under normal full-load conditions, i.e., (6 x full load current) x asymmetry factor of 2.55. The effect of magnetic unbalance is to produce an additional component of radial leakage flux which acts in the same sense 218
throughout the winding. It thus produces a force which is upwards on one winding and downwards on the other (Fig 3.26 (b)). Axial forces under short-circuit are resisted by transmitting them to the core. The top and bottom core frames incorporate pads which bear on the ends of the windings, these pads distributing the load by means of heavy-section pressboard or compressed laminatedwood platforms. The top and bottom core frames, in turn, are linked together by steel tie-bars which have the dual function of resisting axial short-circuit forces and ensuring that when the core and coils are lifted via the top core frames on assembly, the load is supported from the lower frames. These tie-bars can be seen in Fig 3.12 which shows a completed core before fitting of the windings. Since the precise magnitude of these forces depends much upon leakage flux, and the leakage flux pattern also determines the value of reactance, manufacturers nowadays have computer programmes for accurate determination of leakage flux which also, therefore, enable them to assess shortcircuit forces and accurately design for them. 1.5 Tappings and tapchangers Almost all power station transformers incorporate some means of adjusting their voltage ratio by means of the addition or removal of tapping turns. This adjustment may be made on-load, as is usual in generator and station transformers, or by means of an off-circuit switch, or by the selection of bolted link positions with the transformer totally isolated. The degree of sophistication of the system of tap selection depends on the frequency with which it is required to change taps. 1.5.1 Uses of tapchangers
It is first necessary to examine the purposes of tapchangers and the way in which they are used. A more complete discussion of this subject will be found in Chapter 1 of this volume dealing with design and operation of the connections to the grid system and the auxiliary transformers forming the electrical auxiliary system, but the transformer engineer must know what is required of the plant and why. Dealing first with the electrical auxilary system, the design of a suitable supply system for auxiliary plant must cater for all operating conditions, for example, unit start-up, full-load and emergency operation, and the outage of supply equipment. It must also optimise the various component impedances to achieve a suitably economical compromise between the conflicting requirements of fault-level limitation and acceptable voltage regulation. This design task is greatly assisted by the use of off-circuit taps on the 11/3.3 kV and 3.3/0.415 kV auxiliary transformers, especially when precise information regarding loads and operating conditions cannot be established during the design period.
General design and construction Supplies to the I-1V side of the station transformer at 132, 275 or 400 kV may be varied by ±10 07o to suit system loading conditions, under the direction of Grid Control and beyond the control of the power station operating staff. If the 11 kV station voltage is to be maintained sensibly constant, therefore, an onload tapchanger on the station transformer must be available to the station operators. It should be noted that if the stotion operator uses this tapchanger simply to maintain the station 11 kV system voltage constant as the system voltage varies, then the station transformer flux density remains constant. If, however, the operator also endeavours to compensate for regulation on the 11 kV station system, as he may need to do, then this will require an increase in the volts/turn and hence an increase in the flux density. The design flux density of the station transformer must take this operating condition into account. The unit transformer 1-JV terminals are connected to those of the generator whose voltage is maintained within +5% of nominal by the action of the generator AVR. With such close control of its primary voltage, therefore, an on-load tapchanger is not necessary on the unit transformer. It is a wise precaution, however, to provide off-circuit taps so that some adjustment of the voltage ratio may be made should this be found to be necessary for the reasons outlined above with reference to auxiliary transformers. The generator transformer is used to connect the generator whose voltage is maintained within ±5 0/o of nominal, to a 400 kV system which normally may vary by ±10%. This cannot be achieved without the ability to change taps on load. However, in addition to the requirement of the generator to produce megawatts, there may also be a requirement to generate or absorb VArs, according to the system conditions, which will vary due to several factors, for example, time of day, system conditions and required power transfer. Generation of VArs will be effected by tapping-up on the generator transformer, that is, increasing the number of [-IV turns for a given 400 kV system voltage. Absorption of VArs will occur if the transformer is tapped down. As with the station transformer, this mode of operation also leads to variation in flux density which must be taken into account when designing the transformer. The subject is more complex than for the station transformer however, and will be described in more detail in Section 2 of this chapter which deals specifically with the generator transformer.
and a resulting change of impedance. The auxiliary system designer would, of course, prefer to be able to change the voltage ratio without affecting impedance but the best the transformer designer can do is to aim to minimise the variation or possibly achieve an impedance characteristic which is acceptable to the system designer rather than one which might aggravate his problems. Any special measures which the transformer designer is required to take is likely to increase cost and must therefore be totally justified by system needs. Figure 3.27 represents a series of sections through the windings of a two-winding transformer having the tappings in the body of the HV winding. In all three cases the HV winding is slightly shorter than the LV winding in order to allow for the extra end insulation of the former. in Fig 3.27 (a) all tappings are incircuit, Fig 3.27 (b) shows the effective disposition of the windings on the principal tapping and Fig 3.27 (c)
DISPLACEMENT OF CENTRE LINES OF HALF WINDINGS
(a) Maximum tap
(b) Pnncipal tap
x = DISPLACEMENT OF CENTRE 2 LINES OF HALF WINDINGS
1.5.2 Impedance variation
In discussion of the subject of leakage flux and shortcircuit forces, mention has already been made of the unbalance effect created by the provision of tappings. As tappings are added or removed from one of the windings without any compensating change on the other winding, there will be a change in the degree of 'out of balance', a change irt the leakage flux pattern
ci Minimum tap
FIG." 3.27 Effects of tappings within windings 219
Transformers
Chapter 3
when all tappings are out-of-circuit. It can be seen that, although all the arrangements are symmetrical about the winding centreline and therefore have overall axial balance, the top and bottom halves are only balanced in the condition represented by Fig 3.27 (b). This condition will therefore have the minimum leakage flux and hence the minimum impedance. Addition or removal of tappings increases the unbalance and thus increases the impedance. It can also be seen that the degree of unbalance is greatest in Fig 3.27 (c), so that this is the condition corresponding to maximum impedance. A plot of impedance against tap position would thus tend to be of the form shown in Fig 3.28 (a). It can be seen that the tap position for which the unbalance is minimum can be varied by the insertion of gaps in the untapped winding so that the plot is reversed (Fig 3.28 (b)) and, by careful manipulation of the gaps at the centre of the untapped winding and the ends of the tapped winding, a more or less symmetrical curve about the mean tap position can be
+ 10%
NORMAL TAP POSITION
obtained. This is usually the curve which gives minimum overall variation. From this, it will be apparent also that the variation will be reduced if the space which the taps occupy can be reduced to a minimum. While this can be achieved by increasing the current density in the tapping turns, the extent to which this can be done is li mited by the need to ensure that the temperature rise in this section does not greatly exceed that of the body of the winding, since this would then create a hot spot. If it is necessary to insert extra radial cooling ducts in order to limit the temperature rise, then the space taken up by these offsets some of the space savings gained from the increased current density. The designer's control of temperature rise in the taps tends to be less than that which can be achieved in the body of the winding, where the designer can vary the number of sections by adjusting the number of turns per section, with a radial cooling duct every one or two sections. In the taps, the turns per section are dictated by the need to ensure that the tapping leads appear at the appropriate position on the outside of a section, hence one tap must span an even number of sections, with a minimum of two. With the tappings contained in a separate layer, external to the HV winding, the degree of impedance variation throughout the tapping range tends to be less than for taps in the body of the HV winding. It can be seen from Fig 3.29 that the highest degree of bal-
-1 0 %
(a) No gap in untapped winding
mi,■•=soml■
(a) Maximum Tap. All taps in 'boost' a.
+ 10%
NORMAL TAP POSITION
- 1 0%
(b) Gap in untapped winding
FIG. 3.28 Variation of impedance with tap position
220
(b) Principal Tap (no taps in circuit) (c) Minimum Tap condition as (a) but all taps in buck'
FIG. 3.29 Buck/boost tap arrangement
General design and construction ance will be achieved when there are no tapping turns in circuit, provided that the LV and I-1V winding are of the same length. But, as explained in Section 1.4.9 of this chapter, one of the occasions when it is necessary to provide a separate tapping layer is when the HV incling is star-connected and has graded insulation, d with this arrangement both EIV and LV windings an voltage Lest levels so that it ■ \ ill have similar applied is logical tha they should have the same amount of end insulation and thus be of the same length. Furthermore, the physical size of the tapping winding is minimised and the minimum impedance will coincide with the mean tap position if it is arranged that the tapping winding is connected in a 'buck' and 'boost' arrangement. in this arrangement instead of all taps being additive to the minimum HV turns, at one extreme of the tapping range all taps are in circuit but of such a polarity as to subtract from the voltage induced in the main HV winding and at the other end of the range all are connected in the opposite sense, i.e., additive. This arrangement is frequently used on larger transformers, where the saving in space occupied by the tapping winding more than offsets the extra complexity of the on-load tapchanger required to provide buck/boost switching, and the reduced impedance variation is an added benefit.
LINE TERMINAL
SI
1.5,3 Tapchanger mechanisms
The principal of on-load tapchanging was developed in the late 1920s and requires a mechanism which will meet the following two conditions: • The load current must not be interrupted during a tapchange. • No section of the transformer winding may be short-
circuited during a tapchange. Early on-load tapchangers made use of reactors to achieve these ends but in modern on load tapchangers these have been replaced by transition resistors which have many advantages. (In fact, the first resistortransition tapchanger made its appearance in 1929, but the system was not generally adopted in the UK
FIG. 3.30 Resistor transition on-load tapehanger
-
until the 1950s. In the USA, the change to resistors is only now taking place in the 1980s.) The principle of all resistor-transition on-load tapchangers may be seen by reference to Fig 3.30. Alternate tapping connections are brought out from the tapping winding to two banks of selector switches SI and 52. The load current connection, which is usually the neutral in the case of neutral-end tapping windings of star-connected station or generator transformer HV windings, is taken from these selector switches via a diverter switch which Is arranged so that it connects to each bank of selector switches in turn, either solidly when the required tap has been selected, or via a transition resistor (or resistors) at the instant of changeover. This will be
clarified by considering an actual tap change, say from tap 3 to tap 4 in the diagram. With tap 3 selected, the diverter switch is made to the right hand set of main and transition contacts MI and Ti. In order to change to tap 4, the selector switch of bank 52 must first move to contact 4. The diverter switch then starts to move to the left and, as it does so, contact M1 opens first, putting resistor RI in circuit. Further movement of the diverter switch bridges transition contacts Tl and 12, so that load current commences to flow from tap 4, and the section of the tapping winding between taps 3 and 4 will be circulating current through resistors RI and R2. As the diverter switch contact Ti separates, all the load current is transferred to tap 4, and flows via R2 until, finally, contact M2 is made, thus taking all current and shorting out R2. Should the tapchanger be required to return to tap 3, the sequence followed would be the reverse of the above. However, if the 221
Transformers next tapchange is to tap 5, the selector switch mechanism must be driven to the next contact 5 of bank Si before changing over the diverter switch. This is achieved by incorporating 'lost motion' into the drive train so that the initial output from the drive motor operates the selector switches only. For a fuller description of operating mechanisms the reader should consult a manufacturer's operation and maintenance manual. The resistor-transition tapchangers described above brought great advantages to on-load tapchanging. By using a resistor to bridge the transformer taps, the currents to be switched are made to be in phase with the respective voltages across the diverter switch contacts, with the result that the arc extinguishes at current and voltage zero and the restrike voltage across the contacts does not build up to a maximum for a further quarter of a cycle. In addition, the diverter switch mechanism is made of the stored energy pattern, i.e., the drive motor winds up a spring which is then released when fully charged to change over the switch. The mechanism is thus highly reliable in that any drive failure before the spring is fully charged si mply results in the tapchange not taking place and, once released, the spring ensures that the diverter switch changes over and the transformer remains in a safe condition regardless of any subsequent failure of the drive train. Current transfer in these modern tapchangers takes about 40-70 ms. This rapid operation, coupled with the resistive switching, ensures that contact erosion is minimised and reduces arc products which contaminate the oil, with the result that maintenance intervals can be increased and maintenance, when it is required, is simplified. 1.5.4 Single compartment tapchangers
Although the quantity of arc products and extent of oil contamination produced by the diverter switches of a high speed resistor transition tapchanger are very much reduced as compared with reactor transition tapchangers, it is nevertheless practice to mount these in a separate compartment from the banks of selector contacts. This may be partly due to the fact that these tapchangers were developed from reactor gear in which the physical size of the changeover contacts and the extent of maintenance required necessitates a separate compartment, but it has the advantage that it reduces the quantity of oil which may have to be processed regularly and also makes access to diverter switches easier. On a large transformer having a large tapchanger, this arrangement adds little, if anything, to the overall cost. On small auxiliary transformers however, mounting diverter switches and their resistors separately not only adds greatly to costs but also to physical size, with consequent extra indirect costs. The fact that the resistor transition diverter switch arrangement was inherently quicker and cleaner than 222
Chapter 3 its predecessor, coupled with the objective of reducing the cost of the smaller units, led to the further development of the resistor transition principle to produce small single compartment tapchangers — both selector and diverter switch located in the same compartment — for smaller transformers. The following description of the operation of a small single compartment tapchanger is based on that of the Ferranti DS Series shown diagrammatically in Fig 3.31 and pictorially in Fig 3.32. Speed of operation has been increased, compared with the separate compartment types, by the use of a single transition resistor and by the combination of selector and diverter switches into a single assembly which achieves the necessary changeover with the minimum of movement. The stored energy device consists of a falling weight and tensioned spring wound up by a drive motor so that, when released, the weight falls very rapidly aided by the spring. The main current carrying contact (C) is shown (Fig 3.31 (a)) connecting tap contact Ti to the neutral point of the transformer winding, with the main auxiliary arcing contact a also in contact with T1 The switching sequence of changeover to tap contact 12 is as follows: • When the stored energy mechanism operates and the moving contact assembly commences to travel, the main current carrying contact C opens and the circuit is maintained via the main auxiliary arcing contact a. • Transitional contact t then makes contact with T2 and the bridging resistor R is then connected between tap contacts T1 and T2 (Fig 3.31 (b)). • The main auxiliary contact a now breaks contact with Ti leaving resistor R momentarily in circuit to carry the load current. • Contact a then makes contact with T2 whilst transitional contact t rolls round tap contact T2. (Fig 3.31 (c)). The bridging resistor R is thereby shorted out and the circuit is made via the main auxiliary arcing contact a. • Transitional contact t breaks from T2. • Finally, as the moving-contact assembly reaches the end of its travel, the main current carrying contact C closes on tap contact 12 (Fig 3.31 (d)). The main current carrying contact C does not make or break current and should, therefore, last the lifetime of the transformer. 1.5.5 1n tank tapchangers -
Both the separate compartment and single compartment tapchangers have been contained separately from the core and windings so that even the selector switches, which do not break current, are not operating in the
General design and construction
-71
(1:1} Transiiional position A
a: Rt.rning position tap 1
—2
17
(d) Running position tap 2
Transitional position B
FIG. 3.31 Single compartment tapchanger
same oil as that which is providing cooling and insulation for the transformer. The operating mechanism for the selector switch contacts and the contacts t hemselves suffer wear and require maintenance, contact pressures have to be checked, minute metallic particles are produced and will contaminate the oil. However, modern selector switch mechanisms have
been developed since the early 1960s which need very little maintenance and cause very little oil contamination as a proportion of total quantity of oil in the main tank. These tapchangers have been designed for use in the oil in the main tank, an arrangement which the manufacturers claim is cheaper, although the economic argument is a complex one. 223
Transformers
Chapter 3
SWITCH COMPARTMENT
WINDOW FOR OBSERVATION OF TAP POSITION INDICATOR OPERATIONS COUNTER AND FOR INDICATION OF OIL LEVEL OF MOTOR DRIVE AND TIMING GEAR COMPARTMENT
(z)
INSPECTION
MAIN FRONT COVER
FIG.
3.32 Ferranti DS series tapchanger
They have the advantage that all tapping leads can be formed and connected to the appropriate selector switch contacts before the transformer is installed in the tank. With the separate compartment pattern, the usual practice is for selector switch contacts to be mounted on a base board of insulating material which is part of the main tank and forms the barrier between the oil in the main tank and that in the selector switch compartment. The tapping leads thus cannot be connected to the selector contacts until the core and windings have been installed in the tank. This is 224
a difficult fitting task, requiring the tapping leads to be made up and run to a dummy selector switch base during erection of the transformer and then disconnected from this before tanking. Once the windings are within the tank, access for connection of the tapping leads is restricted and it is also difficult to ensure that the necessary electrical clearances between leads are maintained. With in-tank tapchangers it is still necessary to keep the diverter switch oil separate from the main-tank oil. This is usually achieved by housing the diverter switches within a cylinder of glass-reinforced
General design and construction resin mounted above the selector switch assembly. When the transformer is installed within the tank, moval of the inspection cover which forms the top re plate of this cylinder provides access to the diverter switches. These are usually removable via the top of he cylinder for maintenance and contact inspection. Such an arrangement is employed on the Reinhausen is a German design, manufactured t,pe NI series which UK urder licence by Associated Tap Changers in the Limited. It i illustrated in Fig 3.33 and has been used on the generator transformers of the Rihand Power Station in India.
1.5.6 Off-circuit tapchangers As explained in Section 1.4.1 of this chapter, the off-circuit tapping switch enables accurate electrical auxiliary system voltage levels to be set when the power station comes into operation. Once selected, the transformer may remain at that setting for the remainder of its operating life. Most off-circuit tapping switches use an arrangement similar to the selector switch mechanism of the on-load tapchanger, employing similar components, but if these selector contacts are not operated occasionally a build up of pyrolytic carbon can occur at the contact faces. This increases contact resistance which can lead to contact arcing and, in turn, produces more carbon. Ultimately a runaway situation is reached and the transformer will probably
trip on Buchholz protection. To avoid the formation of pyrolytic carbon on off-circuit tapchangers, it is vital that the switch has adequate contact pressure and that it is operated through its complete range once per year to wipe the contact faces clean. Because of these problems, the CEGB has in recent years specified that ratio adjustments on unit transformers and other auxiliary transformers, which would, hitherto, have had off-circuit tapping switches, should be carried out by means of links under oil within the transformer tank. The links must be located at the top of the tank so that access can be obtained with the minimum removal of oil, but provided this is specified, tapchanging is relatively simple and reliability is greatly improved. In fact, the greatest inconvenience from this arrangement occurs during works testing, when the manufacturer has to plan his test sequence carefully in order to minimise the number of occasions when it is necessary to change taps. More tapchanges will probably be made at this time than throughout the remainder of the transformer lifetime.
DIVERTEFI SIMTC1-1uNIT
1.6 Tanks, connections and auxiliary plant 1.6.1 Transformer tanks TAP
SELECTOR
FIG. 3.33 Reinhausen type M tapchanger
The transformer tank provides the containment for the core and windings and for the dielectric fluid. It must withstand the forces imposed on it during transport. On larger transformers, it usually also provides support for the core during transport. All but the smallest transformers, are impregnated with oil under vacuum: the tank acts as the vacuum vessel for this operation. Transformer tanks are almost invariably constructed of welded boiler plate to BS4630. The tank must have a removable cover so that access can be obtained for the installation and future removal, if necessary, of core and coils. The cover is fastened by a bolted flange around the tank at a high level so that it can be removed for inspection of core and coils, if required, without draining all the oil. The cover is normally the simplest of fabrications, often no more than a stiffened flat plate. It should be inclined to the horizontal at 225
Transformers
Chapter 3
■■■•■••••■■
about 1 ° , so that it will not collect rainwater: any stiffeners should also be arranged so that they will not collect water, either by the provision of drain holes or by forming them from channel sections with the open face downwards. The tank is provided with an adequate number of removable covers, allowing access to bushing connections and to core earthing links, off-circuit tapping li nks and the rear of tapping selector switches. Usually the need for the manufacturer to have access to these items in the works ensures that adequate provision is made. All gasketed joints on the tank represent a potential source of oil leakage, so these should be kept to a minimum. The main tank cover flange usually represents the greatest oil leakage threat, since, being of large cross-section, it tends to provide a path for leakage flux, with the resultant eddy current heating leading to degradation of gaskets. Removable covers, whilst being large enough to provide adequate safe access should also be small and light enough to enable them to be lifted safely by maintenance personnel on site. Occasionally the tanks of larger transformers may be provided with deep covers, so that the headroom necessary to lift core and coils from the tank is reduced. This arrangement should be avoided, if possible, since a greater quantity of oil needs to be removed should it be necessary to lift the cover and it requires a more complex cover fabrication. Mention has been made of the need to avoid, or reduce, the likelihood of oil leaks. The welding of transformer tanks does not demand any sophisticated processes but it is nevertheless important to ensure that they are given an adequate test for oil tightness during manufacture. CEGB practice is to apply a pressure of 700 mbar, or the normal pressure plus 350 mbar, whichever is the greater, for 24 hours. This must be contained without any leakage. The tank must carry the means of making the electrical connections. There are cable boxes for all voltages 11 kV. Above this voltage air bushings are normally used, although increasing use is now being made of SF6-filled connections between transformer and switchgear at 132 kV and above. Tanks must be provided with valves for filling and draining. These also enable the oil to be circulated through external filtration and drying equipment prior to initial energisation on site, or during service when oil has been replaced after obtaining access to the core and windings. Lifting lugs or, on smaller units, lifting eyes must be provided, as well as jacking pads and haulage holes to enable the transformer to be manoeuvred on site. An oil sampling valve must also be provided to enable a sample of the oil to be taken for analysis with the minimum of disturbance or turbulence, which might cause changes to the dissolved gas content of the sample and thereby lead to erroneous diagnosis. The sampling valve is normally located about one metre above the tank base in order to obtain as representative a sample as possible. 226
Transformer tanks also have a device to allow the relief of any sudden internal pressure rise, such as that resulting from an internal fault. Until a few years ago, this device was usually a bursting diaphragm. This had the disadvantage that, once it had burst, it allowed art indefinite amount of oil to be released, which might aggravate any fire associated with the fault, and also it left the windings open to the atmosphere. The bursting diaphragm has been superseded by a spring-operated self-resealing device which only releases the volume of oil necessary to relieve the excess pressure before resealing the tank. As shown in Fig 3.34, it is essentially a spring-loaded valve providing instantaneous amplification of the actuation force.
I NNER SPRING
COV E R
OUTER SPRING
ALARM SIVITCM ASSEMBLY
ALARM P.ESET ARM RISC
FLANGE
OUTER GASKET FLANGE GASKET
I NDICATOR PIN
TANK TOP FLANGE
BLEED PORT
FIG. 3.34 Qualitrol pressure relief device
The unit is mounted on a transformer by lugs on the flange and sealed by a mounting gasket. A springloaded valve disc is sealed against inner and outer gasket rings by the springs. The valve operates when the oil pressure acting on the area inside the inner gasket ring exceeds the opening force established by the springs. As the disc moves upwards slightly from the inner gasket ring, the oil pressure quickly becomes exposed to the disc area over the diameter of the outer gasket ring, resulting in a greatly increased force, and causing immediate full opening of the valve corresponding to the closed height of the springs. The transformer pressure is rapidly reduced to normal and the springs then return the valve disc to the closed position. A minute bleed-port to the outside atmosphere from the volume entrapped between the gasket rings prevents inadvertent valve opening if foreign particles on the inner gasket ring prevent a perfect ring-to-disc seal. A mechanical indicator pin in the cover, although not fastened to the valve disc, moves with it during
General design and construction operation and is held in the operated position by an 0-ring in the pin bushing. This remains clearly visible, indicating that the valve has operated. No pressure relief device can provide complete protection against all internal pressure transients. On the Largest tanks, two such devices at opposite ends of the tank improve the protection. It is usual to place the pressure relief device as high on the tank as possible. This 1.1inimises the static head applied to the spring, thus educing the likelihood of spurious operation in the event of a 'normal' pressure transient, for example, the starting of an oil pump. However, with the pressure relief device located at high level, there is the risk that operation might drench an operator with hot oil; to prevent this, an enclosure is provided around the device to contain and direct the oil safely down to plinth level. Such enclosure must not, of course, create any significant back pressure which would prevent the relief device from performing its function properly: a minimum cross-section for any ducting of 300 cm 2 is usually specified. To complete the list of fittings on the transformer tank, it is usual to provide a pocket, or pockets, in the cover to take a thermometer for measurement of top oil temperature, a diagram/nameplate to provide information of transformer details, and an earthing terminal for the main tank earth connection. 1.6.2 Oil preservation equipment — conservators
Although it is now common for many of the smaller distribution transformers to dispense with a conservator (see, for example, ESI Standard 35.1), all oilfilled transformers associated with power station auxiliary systems have conservators, as do the unit, station and generator transformers. The use of a conservator allows the main tank to be filled to the cover, thus permitting cover-mounted bushings, where required, and it also makes possible the use of a Buchholz relay (see below). The conservator reduces the area of the interface between air and oil. This reduces the oxidisation of the oil and also reduces the level of dissolved oxygen, which would otherwise tend to shorten insulation life. Recent investigation, for example that of Shroff and Stannett (1985) 161, has highlighted the part played by dissolved oxygen in accelerating insulation ageing. Although, to date, no special measures have been implemented in CEGB power stations beyond the use of conservators, it is possible that in the near future some arrangement might be introduced to reduce further the degree of contact between oil and air; for example, this could be simply achieved by the use of a parallel-sided conservator having a 'float' covering the surface of the oil. It is also necessary to exclude moisture from the air space above the conservator oil level, in order to maintain the dryness of the transformer oil. For
transformers below 132 kV, this space is vented through a device containing a drying agent (usually silica gel, impregnated with cobalt chloride) over which the air entering the conservator is passed. When the moisture content of the silica gel becomes excessive, as indicated by the change in colour of the cobalt chloride from blue to pink, its ability to extract further moisture is reduced and it must be replaced by a further charge of dry material. The saturated gel can be reactivated by drying it in an oven. The effectiveness of this type of breather depends upon a number of factors; the dryness of the gel, the moisture in the incoming air and the ambient temperature being the most significant. If optimum performance is to be obtained from a transformer having a [-IV winding of 132 kV and above or, indeed, any generator transformer operating at high load factor, then it is desirable to maintain a high degree of dryness of the oil, typically less than 10 parts per million by volume at 20 ° C. Although oil treatment on initial filling can achieve these levels, moisture levels tend to increase over and above any moisture which is taken in through breathing, since water is a product of normal insulation degradation, and this is taking place all the time that the transformer is on load. It is desirable, therefore, to maintain something akin to a continuous treatment to extract moisture from the oil. This is the principle employed in the refrigeration type of breather, illustrated in Fig 3.35. Incoming air is passed through a low temperature chamber which causes any water vapour present to be collected on the chamber walls. The chamber is cooled by means of thermoelectric modules in which a temperature difference is generated by the passage of an electric current (the Peltier effect). Periodically the current is reversed; the accumulated ice melts and drains away. In addition to the drying of the incoming air, this type of breather can be arranged such that the thermosyphon action created between the air in the cooled duct and that in the air space of the conservator creates a continuous circulation and, therefore, a continuous drying action. As the air space in the conservator becomes increasingly dried, the equilibrium level of moisture in the oil for the pressure and temperature conditions prevailing will be reduced so that water will be driven off and this, in turn, causes moisture to migrate from the insulation to the oil, so that a continuous drying process takes place. The conservator is provided with a sump by arranging that the pipe connecting with the transformer projects into the bottom by about 750 mm. This collects any sludge which might be formed over a period of years by oxidation of the oil. One end is usually made removable so that, if necessary, the internals may be cleaned out. One end-face usually incorporates a prismatic oil level gauge: this should be angled downwards by some 10-15 ° , so that it can be easily viewed from plinth level. 227
Chapter 3
Transformers
IN LZT p ip
B COOLING FINS THERMO. ELECTRIC MODULES BREATHING DUCT
OUTLET PIPE CONNECTED TO CONSERVATOR ABOVE OIL LEVEL
TERMINAL BOX
OIL SEAL
WATER DRAIN
SECTION A-A
1FtAP. ICE-SEALED DURING FREEZING. OPEN DURING DEFROST
THERMAL INSULATION
COOLING AIR DUCT
CONDUCTION LEADS
SECTION 8-9
FIG. 3.35 Refrigeration breather
228
As mentioned above, the provision of a conservator also permits the installation of a Buchholz relay (sometimes termed a 'gas and oil operated relay). This is installed in the run of pipe connecting the conservator to the main tank. In this location, the relay collects any gas produced by a fault inside the tank. The presence of this gas causes a float to be depressed which is then arranged to operate a pair of contacts which can be set to 'alarm', or 'trip', or both, dependent upon the rate of gas production. A detailed description of this device can be found in most transformer textbooks, for example, the J and P Transformer Book [7]. In order to ensure that any gas evolved in the tank is vented to the conservator it is necessary to vent every high point on the tank cover, for example, each bushing turret, and to connect these to the conservator feed pipe on the tank side of the Buchholz
relay, normally using about 20 mm bore pipework. The main connecting pipe between tank and conservator is 75 or 100 mm bore, depending upon the size of the transformer. 1.6.3 Bushing connections
A bushing is a means of bringing an electrical connection from the inside to the outside of the tank. It provides the necessary insulation between the connection and the earth potential of the tank, and forms a pressure-tight barrier enabling the necessary vacuum to be drawn for the purpose of oil impregnation of the windings. It must ensure freedom from leaks during the operating lifetime of the transformer. The bushing must also, of course, provide the required current carrying path with an acceptable temperature rise. Varying degrees of sophistication are necessary to meet these requirements, depending on the voltage and/or current rating of the bushing. Figure 3.36 shows an 11 kV bushing with a current rating of about 1000 A. This has a central current carrying stem, usually of copper, and the insulation is provided by a combination of the porcelain shell and the transformer oil. Under oil, the porcelain surface creepage strength is very much greater than in air, so that the 'below oil' portion of the bushing has a plain porcelain surface. The 'air' portion has the familiar shedded profile in order to provide a very much longer creepage path, a proportion of which is 'protected' so that it remains dry in rainy conditions. At 33 kV and above, it is necessary to provide additional stress control between the central high voltage lead and the external, 'earthy' flange. This can take the form either of a synthetic-resin-bonded paper multifoil capacitor or of an oil-impregnated paper capacitor of similar construction. Figure 3.37 shows a 400 kV oil-impregnated paper bushing in part-section. The radial electrical stress is graded through the insulant by means of the concentric capacitor foils and the axial stress is controlled by the graded lengths of these. The capacitor is housed between an inner
General design and construction
RAINSHED
FLANGE
FIG.
3.36 11 kV bushing 229
Transformers
Chapter 3
TERMINAL PALM
OIL CONSERVATOR
PRISMATIC OIL
GAUGE
CILIMPREONATED PAPER CORE
PORCELAIN SHELL
EARTH BAND FOR CT ACCOMMODATION
Fcc. 3.37 400 kV oil-impregnated-paper bushing
conducting tube and the outer porcelain casing. The interspace is oil-filled and the bushing head, or 'helmet', provides oil-expansion space and is fitted with a sight glass to give indication of oil level. Clearly, this type of bushing is designed for installation at, or near, the vertical position. The bushing illustrated is of the so-called 're-entrant' pattern in that the connection to the line-lead is housed within the lower end of the bushing. This has the effect of foreshortening the under-oil end of the bushing but requires a more complex lower porcelain section, which adds considerably to the cost. In order to make the electrical connection to the bushing, the HV lead terminates in a flexible pigtail which is threaded through the central tube and connected inside the head of the bushing. The heavy insulation on the line-lead, how230
ever, is only taken just inside the re-entrant end of the bushing. With this arrangement, an inverted conical section gas-bubble deflector must be fitted beneath the re-entrant end of the bushing to ensure that any gas evolved within the transformer tank is directed to the Buchholz relay and not allowed to collect within the central stem of the bushing. In this bushing, the designer's main difficulty is to provide an insulation system capable of withstanding the high working voltage. The low voltage bushings of a large generator transformer present a different problem. Here, the electrical stress is modest but the difficulty is in providing a current rating of around 14 000 A, the phase current of an 800 MVA unit. Figure 3.38 shows a bushing rated at 33 kV, 14 000 A. The current is carried by the large central copper cylinder, each end of which carries a palm assembly to provide the heavy current connections to the bushing. The superior cooling capability provided by the transformer oil at the 'under-oil' end of the bushing means that only two parallel palms are required. At the air end of the bushing, it is necessary to provide a very much larger palm surface area and to adopt a configuration which ensures a uniform distribution of the current. It has been found that an arrangement approximating to a circular cross-section — here, octagonal — achieves this better than one having plain parallel palms. These palms may be silver-plated to improve their electrical contact with the external connectors, but in fact recent CEGB experience has shown that a better connection can be made to plain copper palms, provided that the joint is made correctly; for more information on this aspect, the reader is referred to Chapter 4 which deals with generator main connections. Insulation is provided by a synthetic-resin-bonded paper and foil condenser bushing and, as can be seen From the diagram, this also provides the means of mounting the flange. External weather protection for the air end is provided by the conventional shedded porcelain housing. An air-release plug on the upper-end flange allows air to be bled from the inside of the assembly, so that it can be filled with oil under the head of the conservator. 1.6.4 SF6 connections
With the advent of 400 kV SF6-insulated metalclad switchgear in the 1970s, the benefits of making a direct connection between the switchgear and transformer were quickly recognised. At Dinorwig power station, for example, transformers and 400 kV switchgear are all accommodated underground. The transformer hall is immediately below the 400 kV switchgear gallery and 400 kV metalclad connections pass directly through the floor of this to connect to the transformers beneath. Even where transformers and switchgear cannot be quite so completely integrated, there are space saving benefits if 400 kV connections can be made to
General design and construction
CURRENT CARRYING CYLINDRICAL 'STEM MOUNTING FLANGE
IL‘1116.
' IL
COMPRESSION SPRINGS
SRPB BUSHING CAPACITOR
11
1.. . ■.....■mige. 000 000 000 000 000 00 0 2 PARALLEL UNDER OIL' PALMS
SPRING PLATE
AIR CONNECTION PALMS IN OCTAGON FORMATION OUTER SHEDDED PORCELAIN
FIG.
3.38 Simplified cross-section of a 33 kV 14 000 A bushing
the transformer, totally enclosed within SF6 trunking. Figure 3.39 (a) shows the arrangement employed at Heysham 2. The 400 kV cable which connects to the 400 kV substation is terminated with an SF6 sealingend. SF6 trunking houses line isolator, earth switch and surge diverter. By mounting the SF6/oil-bushing horizontally, the overall height of the cable sealing-end structure can be reduced. The construction of the SF6/oil-bushing is similar to that of the air/oil bushing described previously in that stress control is achieved by means of an oilimpregnated paper capacitor, oil-immersed but housed within a cast resin rather than a porcelain shell. The 'under oil' end is 'conventional', i.e., it is not reentrant and, since there is no need for the lengthy aircreepage path used in an oil/air bushing, the SF6 end is very much shorter than the air equivalent. Oil expansion and contraction is accommodated by means of a small pressurised conservator. Loss of oil is detected by means of a pressure-low switch which can be arranged to initiate an alarm. Since the SF6 trunking operates at a pressure of about 3 bar, leakage of SF 6 gas into the bushing must be regarded as a real possibility and so this, too, is alarmed by means of a pressure-high switch. Electrical connections are
made to the bushing by means of plain rectangular bolted palms at either end. 1.6.5 Cable box connections
Cable boxes are the preferred means of making connections at 11 kV, 3.3 kV and 415 V, as in other power station auxiliary electrical plant. Cabling principles are dealt with more fully in Chapter 6 of this volume but the following section reviews them insofar as they affect the power transformer terminations. Modern polymeric-insulated cables can be housed in air-insulated boxes. Such connections can be broken with relative simplicity and it is not therefore necessary to provide the separate disconnecting chamber needed for a compound-filled cable box with a paperinsulated cable. LV currents of up to 3000 A, the switchgear limit, are used for auxiliary power transformers and with cable current ratings of 600-800 A, as many as five cables per phase can be necessary for the LV connections of the largest unit and station transformers. For the smallest transformers of 1 MVA or less, one cable per phase is sufficient. Since the very rapid price rise of copper which took place in the 1960s, power cables are made almost exclusively 231
nor-
Transformers
Chapter 3
LV BUSBARS 400 kV SF6 TRUNKING
UNE BELLOWS ISOLATOR
SF6 SEAUNG END
400kV CABLE SURGE ARRESTER
/IL
ACOUSTIC ENCLOSURE
BUN()
FIG.
GENERATOR TRANSFORMER
3.39 Simplified arrangement of 400 kV SF6 connection to generator transformer
of aluminium. These tend to be bulkier and stiffer than their copper counterparts and this has to be taken into account in the cable box design. Each cable has its own individual glandplate so that the jointer can gland the cable and then manoeuvre it into position in order to connect it to the terminal. Both cable core and bushing will have palm-type terminations which are connected with a single bolt. Again, in order to give the jointer some flexibility and to provide the necessary tolerances, it is desirable that the glandplate-to-bushing terminal separation should be at least 320 mm. For cable ratings of up to 400 A, non-magnetic glandplates should be used. For ratings above 400 A, the entire box should be constructed of non-magnetic material in order to reduce stray losses within the shell which would otherwise increase its temperature rise, with the possible risk of overheating the cable insulation. To enable the box to breath and to avoid the build-up of internal condensation, a small drain hole, say 12 mm in diameter, is provided in one glandplate. Figure 3.40 shows a 3.3 kV air-insulated cable-box having a rating of about 2400 A with 4 x 400 mm 2 aluminium cables per bushing. At 11 kV, some stress control is required in an air-insulated box, so bushing and cable terminations are designed as an integrated assembly, as shown in Fig 3.41 (a). Figure 3.41 (b) shows a cross-section of the mouldedrubber socket connector which is fitted to the end of the 11 kV cable. This has internal and external semi232
y: //// I
BUSHING MOUNTING PLATE
BUSHING ASSEMBLY & MOUNTING TOGS 2562
APERTURE & FLANGE ON TANK TOGS 2562
2500A three ar tour gland entry enclosure
FIG. 3.40 3.3 kV cable box
conductive screens: the inner screen, the cable conductor connector and the outer provides continuity for the cable outer screen, so that this encloses the entire termination. The external screen is bonded to earth by connection to the external lug shown in the figure. The joint is assembled by fitting the socket connector over the mating bushing and then screwing the insulating plug, containing a metal threaded insert, onto the end of the bushing stem. This is tightened by means of a spanner applied to the hexagonal-nut insert in the outer end of this plug. This insert also serves as a capacitative voltage test point. After making the
General design and construction ...■•••■•
restricted access. However, it is CEGB practice to enclose the termination within a non-magnetic sheet steel box to provide protection and phase isolation. Should a fault occur, this must be contained by the box which ensures that it remains a phase-to-earth fault, normally limited by a resistor at the system neutral point, rather than developing into an unrestricted phase-to-phase fault. 1.6.6 Tank mounted coolers -
0
0
!!
1-7
I
0
s.NGLE CORE powER SUPPLY VIEW ON FRONT WITH LID REMOVED
al 114V
cable box
ENTRANCE PORT FOR MATING I /kV BUSHONG
MEIER VOLTAGE INSULATING CAP TEST PLUG POINT
OUTER SCREEN I NSULATION CONDUCTOR CONNECTOR INTERNAL SCREEN
EARTHING LUG
01 1 1 kV elaslimoal elbow
FIG. 3.41 11 kV cable box and section of 11 kV
elastimold elbow termination
joint, this is finally covered by the semiconducting moulded-rubber cap. Since the external semi-conductive coating of this type of connector is bonded to earth, there would be no electrical hazard resulting from its use without any external enclosure and, indeed, it is common practice for a connector of this type to be used in this way in many European countries provided that the area has
Tank-mounted radiators represent the simplest option for cooling smaller power station transformers. These are suitable for all auxiliary transformers from the smallest in common use (about 0.8 MVA), to the largest, which are usually 12.5 MVA, 11/3.3 kV. They are available in various patterns but all consist basically of a number of flat 'passes' of edge-welded plates connecting a top and bottom header. Oil flows in and out of the radiators via the headers and is cooled as it flows downwards through the thin sheet-steel passes. The arrangement is generally considered to be suitable only for transformers having natural oil and natural air circulation, i.e., ONAN cooling, as defined in BS171. It would be possible to suspend a fan below the radiators to provide a forced draught, ONAF arrangement.' At best this might enable the transformer rating to be increased some 10-15 070, but only at the extra cost and complexity of control gear and cabling for, say, two fans. Achievement of this modest uprating would require that the radiators be grouped in such a way as to obtain optimum coverage by the fans. With small transformers of this class, much of the tank surface is normally taken up with cable boxes, so that very little flexibility remains for location of radiators. In addition, to provide space below the radiator for installation of a fan requires that the length of the radiator must be reduced, so that the area for selfcooling is reduced. It is frequently a problem to accommodate tankmounted radiators whilst leaving adequate space for access to cable boxes, the pressure relief vent pipe and the like. The cooling-surface area can be increased by increasing the number of passes on the radiators, but there is a limit to the extent to which this can be done, dictated by the weight which can be hung from the top and bottom headers. It is possible to make the radiators slightly higher than the tank so that the top header has a swan-necked shape: this has the added benefit that it also improves the oil circulation by increasing the thermal head developed in the radiator. However, this arrangement also increases the overhung weight and has the disadvantage that a swan-necked header is not as rigid as a straight header, so that the weight-bearing limit is probably reached sooner. The permissible overhang on the radiators can be increased by providing a small stool at the outboard end, so that a proportion of the weight bears directly onto the 233
Transformers transformer plinth; however, since this support is not available during transport, one of the major benefits from tank-mounted radiators, namely, the ability to transport the transformer full of oil and fully-assembled, is lost. Each radiator should be provided with isolating valves in the top and bottom headers as well as drain and venting plugs, so that it can be isolated, drained and removed should it leak. The valves may be of the cam-operated butterfly pattern and, if the radiator is not replaced immediately, should be backed up by fitting of blanking plates with gaskets. Radiator leakage can arise from corrosion of the thin sheet steel, and measures should be taken to protect against this. Because of their construction, it is very difficult to prepare adequately and to apply paint protection to radiators under site conditions, so that if the original paint finish has been allowed to deteriorate, either due to weather conditions or from damage in transit, it can become a major problem to make this good. This is particularly so at seaside sites. The CEGB, therefore, now specifies that plate-type radiators for power station transformers must be hot-dip galvanised in the manufacturer's works prior to receiving an etchprime, followed by the usual paint treatment in the works. 1.6.7 Separate cooler banks
As already indicated, one of the problems with tankmounted radiators is that a stage is reached when it becomes difficult to accommodate all the required radiators on the tank surface, particularly if a significant proportion of this is taken up with cable boxes. In addition, with the radiators mounted on the tank, the only straightforward option for forced cooling is the use of forced draught or induced draught fans, and, as was indicated in Section 1.4.11 of this chapter, the greater benefits are gained by forcing and directing the oil flow. However, many utilities, particularly in the USA, do make use of tank-mounted radiators for very large transformers and it might, therefore, be worthwhile considering the merits and disadvantages of these in relation to the separate free-standing cooler arrangement favoured by the CEGB. Advantages
• More compact arrangement saves space on site. • Can be transported as a single entity, which considerably reduces site-erection work. • Allegedly cheaper due to saving of pipework and headers and frame/support structure. Disadvantages
• Forced-cooling must usually be restricted to fans only, due to the complication involved in providing a pumped system. 234
Chapter 3 • Access to the transformer tank and to the radiators themselves for maintenance/painting is extremely difficult. • A noise-attenuating enclosure cannot be fitted to the tank. If these advantages are examined more closely, it becomes apparent that these may be less real than at first sight. Although the transformer itself might well be more compact, if it is to achieve any significant increase in rating from forced cooling, a large number of fans will be required, and a considerable space must be left around the unit to ensure a free airflow without the danger of recirculation. In addition, since the use of forced and directed oil allows a very much more efficient forced cooled design to be produced, the apparent saving in pipework and cooler structure can be easily offset. Looking at the disadvantages, the inability to fit a noise-attenuating enclosure can be a serious problem for larger transformers, i.e., station and generator transformers especially since, in order to allow free access for cooling air, these must be located in an open situation. The protagonists of tank-mounted radiators tend to use bushings mounted on the tank cover for both HV and LV connections, thus leaving the tank side almost entirely free for radiators. Having stated the arguments in favour of freestanding cooler banks, it is appropriate to consider the merits and disadvantages of forced as against natural cooling for power station use. Adopting OFAF cooling for say, a 60 MVA station transformer, incurs the operating cost of pumps and fans, as well as their additional first cost and that of the necessary control gear and cabling. Also, there is slightly-poorer reliability in. a transformer which relies on other auxiliary equipment, compared with an ONAN transformer having no electrically-driven auxiliaries. On the credit side, there is a considerable reduction in the plan area of the cooler bank, resulting in significant space saving of the overall layout. Such an OFAF-cooled station transformer is rated to deliver full output for the start-up of a unit during an outage on the second station transformer, so that for most of its life the loading will be no more than its 30 MVA ONAN rating. Under these circumstances, it is reasonable to accept the theoretical reduction in reliability and the occasional cooler equipment losses as a fair price for the saving in space. On the other hand, a unit transformer is required to operate at or near to full output whenever its associated generator is on load, so reliance on other ancillary equipment is less desirable and, if at all possible, it is preferable to find space in the layout to enable it to be totally naturallycooled. If a transformer is provided with a separate freestanding cooler bank, it then becomes possible to raise the level of the radiators to a height which will create
General design and construction an adequate thermal head to ensure optimum natural circulation. The longest available radiators can be used to minimise the plan area of the bank, consistent with maintaining a sufficient area to allow the required number of fans to be fitted. It is usual to specify that full forced-cooled output can be obtained with one fan out of action. Similarly, pump failure should be catered for by the provision of two pumps, each capable of delivering full flow. If these are installed in parallel branches of cooler pipework, then it is necessary to ensure that the non-running pump branch cannot provide a return path for the oil, thus allowing this to by-pass the transformer tank. Normally this would be achieved by incorporating a non-return valve in each
branch. However, such a valve would create too much head loss to allow the natural circulation necessary to provide an ONAN rating. The solution is to use a flapvalve of the type shown in Fig 3.42, which provides the same function when a pump is running but will take up a central position with minimal head loss for thermally-induced natural circulation. 1.6.8 Water cooling
In the past, water was a common choice of coolant medium for many power station transformers, including practically all generator transformers and most station and unit transformers. This was logical, since there is an ample source of cooling water available in the vicinity of these transformers and oil/water heat exchangers are compact and thermally efficient. Such an arrangement does not provide for a self-cooled rating, since the head loss in oil/water heat exchangers precludes natural oil circulation, but (as explained above) a self-cooled rating is only sensible for the station transformer. The provision of a cooling water
FLOW DIREOTtON
Ftc. 3.42 Oil flap-valve
supply appears to be low cost compared with the cost of running and providing fans, so that water cooling often appears to be more economical. The precise cost of cooling water depends on the source, but it is often pumped from river or sea and when the cost of this is taken into consideration, the economics of water cooling become far less certain. In the early 1970s, after a number of major generator transformer failures attributable to water entering the oil through cooler leaks, the CEGB reassessed the philosophy of water cooling. The high cost of these failures, both in terms of increased generating costs due to the need to operate lower-merit plant and the repair costs, as well as pumping costs, resulted in a decision to adopt a forced-air cooled arrangement for the Littlebrook D generator transformers and this has since become the standard, whenever practicable. The risk of water entering the transformer tank due to a cooler leak has long been recognised and is normally avoided by ensuring that the oil pressure is at all times greater than that of the water, so that leakage will always be in the direction of oil into water. It is difficult to ensure that this pressure difference is maintained under all possible conditions of operation and malfunction. Under normal conditions, the height of the transformer conservator tank can be arranged such that the minimum oil-head will always be above that of the water. However, it is difficult to make allowance for operational errors, for example, the wrong valve being closed, so that maximum pump discharge pressure is applied to an oil/water interface, or for equipment faults, such as a pressure reducing valve which sticks open at full pressure. In the past, it was the practice to use devices such as pressure reducing valves or orifice plates to reduce the waterside pressures. However, no matter how reliable a pressure reducing valve might be, the time will come when it will fail, and an orifice plate will only produce a pressure reduction with water flowing through it, so that should a fault occur which prevents the flow, full pressure will be applied to the system. From the above arguments, it has become policy to avoid water cooling as far as practicable. When it is considered essential, special measures are taken to provide an installation of the appropriate integrity. One recent example is the Dinorwig pumped-storage power station where the generator transformers are located underground, making air cooling impracticable on grounds of space and noise. Figure 3.43 shows a diagrammatic arrangement of the cooling adopted for the Dinorwig generator transformers. This uses a two-stage arrangement having oil/towns-water heat exchangers as the first stage, with second-stage water/water heat exchangers having high pressure lake water cooling the intermediate towns water. The use of the intermediate stage with recirculating towns water enables the pressure of this water to be closely controlled and, being towns water, waterside corrosion/erosion of the oil/ water heat exchangers — the most likely cause of 235
GM TRANSF DRIER IA
COOLING WATER CLOSED CIRCUIT GENERATOR MOTOR TRANSFORMER 1 CONSERVATOR TANK
COOLING WATER GENERATOR MOTOR TRANSFORMER 1
HAND OPERATED VALVE NORMALLY CLOSED VALVE
ON WAD TAP CHANGER
NON.RETURN VALVE BALL FLOAT VALVE PRESSURE RELIEF VALVE
tiM rRANSF DRIER lB
GENERATOR MOTOR TRANSFORMER COOLING WATER HEADER TANK 1
HP CW SYSTEM
—— GENERATOR MOTOR TRANSFORMER I COOLING WATER , PUMP 18
GENERATOR MOTOR TRANSFORMER OIL PUMP 1A
GENERATOR MOTOR TRANSFORMER COOLING WATER PUMP IA
GENERATOR MOTOR TRANSFORMER OIL PUMP IC
GENERATOR MOTOR TRANSFORMER OIL PUMP 1E1
4.11
0
GENERATOR MOTOR GENERATOR MOTOR TRANSFORMER WATER/ TRANSFORMER WATER/ WATER COOLER 1A WATER COOLER 18
GENERATOR MOTOR TRANSFORMER OIL/ WATER COOLER 1A
GENERATOR MOTOR T RANSFORMER OIL' WATER COOLER 18
GENERATOR MOTOR TRANSFORMER WATER COOLER IC
3.43 Diagrammatic arrangement of Ditior wig generator transfOrmer cooler circuits
Oaf
S.19U.IJOISUE'Ji
f"
LF GE ND TRANSFORMER OIL
General design and construction cooler leaks — is also kept very much under control. Pressure control is ensured by the use of a header tank maintained at atmospheric pressure. The level in this tank is topped up via the ball valve and a very generously-sized overflow is provided so that, if this valve should stick open, the header tank will not become pressurised. The position of the water pump in the circuit and the direction of flow is such that should the water outlet valve lf the oil/water heat exchanger be inadvertently closed, this too would not cause pressurisation of the heat exchanger. A float switch in the header tank connected to provide a high level alarm warns of either failure of the ball valve or leakage of the raw lake water into the intermediate towns water circuit. Other situations in which water cooling might be justified are those in which the ambient air temperature is high, so that a significantly greater temperature rise of the transformer might be permitted if water cooling is employed. Such an installation might use an arrangement similar to that for Dinorwig described above or, alternatively, a double-tube/double-tubeplate cooler might be employed. With such an arrangement, shown diagrammatically in Fig 3.44, oil and water circuits are separated by an interspace so that any fluid leakage will be collected in this space and will raise an alarm. Coolers of this type are, of course, significantly more expensive than simple single-tube and plate types and heat transfer is not so efficient, so it is necessary to consider the economics carefully before adopting a double-tube/double-tubeplate cooler in preference to an air-cooled arrangement. Another possible option which might be considered in a situation where water cooling appears preferable is the use of sophisticated materials, for example, titanium-tubed coolers. This is usually less economic than a double-tubed/double-tubepiate cooler as described above. Passing mention has been made of the need to avoid both corrosion and erosion of the water side of cooler tubes. A third problem which can arise is the formation of deposits on the water side of cooler tubes which impair heat transfer. The avoidance of all of these requires careful attention to the design of the cooling system and to carefully controlled operation. Corrosion problems can be minimised by correct selection of tube and tubeplate materials to suit the analysis of the cooling water. Deposition is avoided by ensuring that an adequate rate of water flow is maintained, but allowing this to become excessive will lead to tube errosion. If the cooling medium is seawater, corrosion problems can be aggravated and these might require the use of measures, such as the installation of sacrificial anodes or cathodic protection. These measures have been used with success in CEGB stations, but it is important to recognise that they impose a very much greater burden on maintenance staff than does an air cooler, and the consequences of a small amount of neglect can be disastrous.
A fan and its control equipment can operate continuously or under automatic control for periods of two years or more, and maintenance usually means no more than greasing bearings and inspection of contactor contacts. By contrast, to ensure maximum freedom from leaks, most operators of oil/water heat exchangers within the CEGB routinely strip them down annually to inspect tubes, tubeplates and water boxes. Each tube is then non-destructively tested for wall thickness and freedom from defects, using an eddy current probe. Suspect tubes can be blanked off but, since it will only be permissible to blank-off a small proportion of these without impairing cooling, a stage can be reached when complete replacement tubenests are necessary. In view of the significant maintenance requirement on oil/water heat exchangers, it is most advisable to provide a spare cooler and standard practice has, therefore, been to install three 50 0/o-rated coolers, one of which will be kept in a wet standby condition, i.e., with inlet and outlet valves closed but full of clean water, and with the other two in service. The subject of water cooler design and operation is dealt with more fully in Volume C. 1.6.9 Cooler control
Ancillary plant to provide forced cooling must be provided with power supplies and a means of control. At its most basic, this simply takes the form of manual switching at a local marshalling panel, housing auxiliary power supplies, fuses, overloads and contactors. On modern power stations, the philosophy has been to reduce the amount of at-plant operator control and so it is usual to provide remote and/or automatic operation. The simplest form of automatic control uses the contacts of a winding temperature indicator to initiate the starting and stopping of pumps and fans. Further sophistication can be introduced to limit the extent of forced cooling lost should a pump or fan fail. One approach is to subdivide the cooler bank into halves, using two 50%o-rated pumps and two sets of fans. Plant failure would thus normally not result in loss of more than half of the forced cooling. As has been explained in Section 1.6.7 of this chapter, many forced-cooled station transformers and, in some cases, unit transformers have a rating which is adequate for normal system operation when totally self-cooled, so an arrangement which requires slightly less pipework having parallel 100%o-rated duty and standby pumps, as shown in Fig 3.45, is now favoured. This means that flow switches must be provided to sense the failure of a duty pump and to initiate start-up of the standby should the winding temperature sense that forced cooling is required. A large generator transformer will have virtually no self-cooled rating, so that pumps can be initiated from a voltage sensing relay, fed from a voltage transformer 237
Transformers
Chapter 3
TOP WATERBOX
DOUBLE TUBE PLATE
OIL
DOUBLE TUBE
OIL/WATER INTERSPACE
—10- OIL
LEAKAGE ALARM DOUBLE TUBE PLATE
—0,-WATER
BOTTOM WATERBOX FIG. 3.44 Double tube, double tubeplate oil/water heat - exchanger
which is energised whenever the generator transformer is energised. 100 07o-duty and standby pumps are provided, with initiation of the standby pump should flow-failure be detected on the duty pump. Fans can still be controlled from a winding temperature indicator, but it is usual to divide these into two groups initiated in stages, the first group being switched on at a winding temperature of 80 ° C and out at 70 ° C. The second 238
group is switched on at 95 ° C and out at 80 ° C. The total number of fans provided is such that failure of any one fan still enables full rating to be achieved with an ambient temperature of 30°C. The control scheme also allows each pump to serve either in the duty or standby mode and the fans to be selected for either first-stage temperature operation or second-stage operation. In addition, a multiposition mode selector
General design and construction
FIG. 3.45 Oil circuit for ONAN/OFAF cooled unit
transformer
switch allows both pumps and fans to be selected for 'test' to check the operation of the control circuitry. The scheme is also provided with 'indication' and 'alarm' relay contacts connected to the station data processor. For water cooled generator transformers, the fans are replaced by water pumps which can be controlled from voltage transformer signals in the same way as the oil pumps. Again duty and standby pumps are provided, with the standby initiated from a flow switch detecting loss of flow from the duty pump. There is a view that automatic control of generator transformer air coolers is unnecessary and that these should run continuously whenever the generator transformer is energised. Modern fans have a high reliability, so they can be run for long periods continuously without attention. For many large generator transformers, running of fans (whether required or not) results in a reduction of transformer load loss, due to the reduced winding temperature, which more than offsets the additional fan power requirement, so that this method of operation actually reduces operating cost. In addition, the lower winding temperature reduces the rate of usage of the transformer insulation life. An example will assist in making this clear. An 800 MVA generator transformer might typically operate at a throughput of 660 MW and 200 MVAr, which is equivalent to 690 MVA. At 800 MVA, it will 0 have resistance rise and top-oil rise of 70 and 60 ° C, respectively, if the manufacturer has designed these to the BS limits. At 690 MVA, these could be reduced to 45 ° C and 41 ° C, respectively, dependent on the particular design. Then, as explained in Section 1.4.11 of this chapter, the winding hot spot temperature at an ambient temperature of, say, 10 ° C will be given by: Ambient Rise by resistance Half (outlet/inlet) oil Maximum gradient — average gradient
10 45 6 2
fotal
63 ° C
At this ambient, the first fan group will operate under automatic control, tripping in when the hot spot temperature reaches 80 ° C and out at 70 ° C. It is reasonable to assume, therefore, that with these fans running intermittently, an average temperature of 75 ° C will be maintained. Hence, continuous running of all fans will achieve a temperature reduction of about 12 ° C. The power absorbed by twelve fans on a transformer of this rating might typically be 36 kW. Hence, running them continuously rather than intermittently could absorb an additional power somewhere between 2" kW (if half of them would otherwise have run for half the ti me) and 36 kW (if they would otherwise not have run at all). It is not unreasonable, therefore to assume 30 kW extra load. The load loss of an 800 MVA generator transformer at rated power could be 1600 kW. At 690 MVA this would be about 1190 kW. If it is assumed that 85% of this figure represents resistive loss, then this equates to 1000 kW, approximately. A 12 ° C reduction in the average winding temperature would produce a reduction of resistance at 75 ° C of about 3.8%, hence about 38 kW of load loss would be saved. Strictly speaking, this reduction in resistance would cause an approximately 3.8% increase in the other 15% of the load losses, that is about 7 kW additional stray losses would be incurred, so that the power balance [38: (30 + 7)] would approximately break even. However, the figures used are only approximate and, for lower ambients, the savings in load losses would be more real. The important feature, though, is that the lower hot-spot temperature increases insulation life. For example, referring to Section 1.4.11 of this chapter, the 12 ° C reduction obtained in the above example would, theoretically, increase the life of the insulation somewhere between three and fourfold. 1.6.10 Layout of transformer compounds
In planning a transformer layout there are a number of requirements to be considered. All power transformers containing BS148 oil are considered to represent a fire hazard, so they should be located out of doors, although a study of reported statistics suggests that the likelihood of a fire resulting from an incident involving a power station transformer below 132 kV is very low. This is probably because at the lower system voltages, fault levels and protection operating times are such that it is not possible to input sufficient energy in a fault to raise bulk oil temperature to the level necessary to support combustion. The subject of fire hazard is discussed further in Section 2.4 of this chapter, which deals with auxiliary transformers. Having decided to locate oil-filled transformers out of doors the next important consideration is to minimise the lengths of connections. The transformer location should be selected as close as practicable to the load or, for the generator transformer, to the source 239
Transformers
Chapter 3
of supply. This normally leads to transformers being located in two groups.
erator contribute. To minimise the likelihood of faults, as well as to limit the cost of these connections, it is desirable that they should be kept as short as possible. The subject of generator main connections is dealt with more fully in Chapter 4. The LV current of the unit transformer is of the order of twice that on its HV side and usually involves the use of very bulky 11 kV cables to connect to the 11 kV switchgear. To keep these cables as short as possible, the 11 kV unit board is normally placed close by. The same 11 kV switchgear annexe might also house the 11 kV station board, suitably segregated from the unit board, hence its station transformer could also be included in this group provided that, as an alternative source of 11 kV supplies, it too can be fully segregated against any incident which might affect the unit transformer. Recent segregation requirements introduced for nuclear stations now require the station transformer to be removed to a more distant location. This is so that alternative 11 kV supplies can be preserved, even in the event of a major incident, such as an aircraft crash on the site.
Grouping these main transformers together has the advantage that they can share drainage facilities and, since transformer compound drainage involves costly civil works, this is a worthwhile economy. Figure 3.46 shows a typical layout of generator unit and station transformers for two units of a four-unit station. Oil-filled transformers represent a fire hazard. To ensure rapid extinguishing of any fire, each transformer is provided with a fixed waterspray fire protection installation. This consists of a system of spray nozzles located around the transformer and directed towards it which provide a total deluge when initiated, usually by the bursting of any one of a series of glass detector bulbs placed around and above the transformer. Another part of the strategy for rapid extinguishing of a fire is the removal of any spilled oil from the plinth as rapidly as possible. To assist with this, its surface must be smooth concrete. Large drainage trenches are provided and these must have an adequate fall. Clearly large quantities of oil and water cannot be allowed to enter the normal drainage system, so the drainage trenches are taken to interceptor chambers which allow settlement and separation of the oil before allowing the water to be led away. A typical arrangement for a four-unit station is shown in Fig 3.47. Although the plinths are designed to drain rapidly, it is important to ensure that any water which might be contaminated with oil is not allowed to flood into neighbouring areas, so each plinth must be contained within a bund wall which will hold, as a minimum, the total contents of the transformer tank, plus five minutes operation of the fire protection, and this after heavy rain has fallen onto the area. Until quite recently, the standard method of ensuring rapid removal of oil from the surface of the transformer plinth was to install the transformer on dwarf walls, perhaps one metre high, the plinths then con-
UNIT TRANSFORMER 1
PRECIPITATORS
The first group consists of those located immediately outside the turbine hall. This includes the generator
transformer in order to minimise the length of the very heavy-current generator connection and almost certainly the unit transformer also. The generator busbars are large aluminium fabrications which, for reasons of site installation, must be kept as straight and as simple as possible. Those supplying the unit transformer are teed-off the main run; although not having as large a load current as those to the generator transformer, the current under fault conditions is greater than that in the main run, since both the system and the gen-
STATION TRANSFORMER 1
GENERATOR TRANSFORMER 1 TURBINE - GENERATOR 1
1 SkV SWITCHROOM
t
CONTROL ROOM
GENERATOR TRANSFORMER 2
BOILER HOUSE
TURBINE GENERATOR 2
1 1 kV SWITCHROOM
UNIT \ TRANSFORMER 2
FIG. 3.46 Layout of generator, unit and station transformers 240
0 CI-tIMNEY
General design and construction ••••••••
ANSWARIPWAr42•211tgardr
NO GENERATOR TRANSFORMER
_
HP.1E1
-
RENCH
, NO 2 UNIT TRANSFORMER
Ayr—
TRANSFORMER ANNE xE
MAIN ACCESS ROAD
EJ
—
FROM NO 1 COMPOUND
MANHOLE
IA L
4+11
MAIN CHAMBER ----------------------------
4
—
cam
L
OIL INTERCEPTOR
FACIA NOS 3 AND 4 COMPOUNDS
7
—
l_._
.
_J
_I
4■:1: F 0 SURFA TER ci ,g
—
TYPICAL SECTION A.A THROUGH INCERCEPTOR
FIG.
3.47 Arrangement of water and oil drains for transformer plinth
sisting of open mesh about 100 mm below the level of the top of the wall covered with large chippings. Any spilled oil passed through the chippings and the mesh into the chamber below. Such an arrangement allowed burning oil to be led from the surface very rapidly and the fire was quickly extinguished when the chippings were new and in a fairly clean condition. However, it became clear that chippings which had become oily over the years and had acquired a coating of grime, tended to act as a wick in the event of a fire and made it more difficult to extinguish. Figure 3.48 shows the layout of the main transformer plinth at Heysham 2 power station. The generator transformer is a threephase bank of single-phase units. Each phase has both ends of the LV winding brought out to a pair of LV connections side-by-side on one side of the tank. These are connected in delta by means of a phase-isolated air-insulated connection, similar in construction to the main connections to the generator which are themselves teed-off from each corner of this delta. Because of the difficulty in making angled welds, and of designing right-angled turns in the heavy low-voltage connections, it is desirable that these be run as straight as possible, so ideally the generator transformer should face squarely onto the end of the generator. Unit transformer tee-offs can then, if physically possible, tall vertically onto the unit transformer placed beneath the connections and behind the generator transformer. It is important to ensure that each phase of the generator transformer (as well as those of the unit transformer) can be installed and removed with the
minimum disruption to cabling, connections, and to its neighbours. The routes for installation and withdrawal are indicated on the diagram. It should be noted also that the generator transformer cooler, with about 2 MW of losses to dissipate at full-load, is located so that it has at least eight times its plan area of free space around it to ensure an adequate cooling-air supply, with no recirculation. The layout of generator and unit transformers, in particular, must have regard to correct phase-relationships. Although this is true for all transformers, it is the bulky and less flexible arrangement of the connections which makes this so important for these two transformers. This design task is fraught with pitfalls, and incorrectly phased connections can be exceedingly expensive to unscramble. The important convention is that contained in BS171, that the phases A, B and C (or U, V and W) run from left to right when viewed from the HV side of the transformer, but LV terminals are reversed when viewed from the generator. The other conventional rule is that, within a particular winding, the low-numbered connection goes to neutral and the higher-numbered connection goes to the terminal. Referring to Fig 3.49 and recalling that, as indicated in Section 1.1.2 of this chapter, the standard phasor grouping for a 400/23.5 kV generator transformer is Ydl, the star point of the HV winding will be A], B1, C1 and the LV will require a2 to be connected c1, b2 to al and c2 to b1, with a2 becoming terminal a, b2 terminal b, and c2 terminal c. For the simplest arrangement of LV connections, it can thus be seen 241
Chapter 3
Transformers
AIR OIL COOLERS
A. 1 COOLERS:. f' I WITHDRAWAL ROUTE
CONSERVATOR
WITHDRAWAL ROUTES
3 PHASE
GENERATOR TRANSFORMER
UNIT TRANSFORMER 7C
I
400kv CABLE TRENCH
EARTHING z TRANSFORMER STATOR ACCESS UNIT TRANSFORMER 7D
El
B Y R MAIN GENERATOR BUS BARS
FIG. 3.48 Main transformer plinth layout
from Fig 3.49 (b) that terminal 2 of the LV winding will require to be on the right, when viewed from the LV side. Figure 3.49 (b) also shows the arrangement of generator connections required to give red, yellow, blue to phases a, b and c, respectively.
The second group of transformers requiring to be accommodated in the station layout are those stepping down II kV supplies to 3.3 kV and from 3.3 kV to 415 V. Whilst it is permissible for 11 kV cabling to be used. to distribute power for considerable distances around the site, supplies at lower voltages must be placed as close as possible to their loads. Ideally, these transformers should be in the middle of the station. This is not practical for many reasons, not least that oil-filled transformers represent a fire hazard. Often in a coal-fired station, the best compromise is to place them alongside the boiler house, between it and the precipitators. Figure 3.50 shows an outline plan of a two-unit coal-fired station with 242
the location of outdoor 11/3.3 kV and 3.3/0.415 kV transformers identified. Many nuclear stations have separate reactor and turbine buildings, so that transformers can be placed alongside a roadway between them. If the station has only one or two units, often the best location will be to the side of the turbine hall and steam generating plant buildings. Figure 3.51 shows where these transformers might be located in a nuclear station. For all of these possible locations, consideration must be given to: • Clear access for installation and for future removal should this become necessary. • Access for cabling. • The need for fire fighting provision and ensuring that adjacent buildings and plant are not placed at risk if a fire occurs.
General design and construction
II 33k/ TRANSFORMERS
A
331.4 i,41ET) SWiTC ,-EGEAR BOOM
110., SWITCHGEAR
PRECIPiTATORS
UNIT
[.
[ COR I,c11,TORMO L
TURBINE HALL
BOILER HOUSE
I--. UNIT 2
:a)
l•l
AV SWITCHGEAR
IMI
1133kV8.31 a-MEW TRANSFORMERS
FIG. 3.50 Location of 11/3.3 kV and 3.3/0.415 kV transformers in a coal-fired station
ir
TURBINE HALL
acm:si8:::::::s
QJ
III II
EL
BLUE YELLOW RED
IC'
FIG. 3.49
Connections of single-phase generator transformer bank
• The need for adequate drainage. • The provision of necessary oil interception. As with the main transformers it is possible to make economies, particularly in respect of the last three factors, by the grouping of auxiliary transformers together. Any grouping, however, must have in mind the need to segregate alternative sources of supply to main switchboards, so that any single incident would not make both of them unavailable. For smaller auxiliary transformers, providing supplies at 415 V, the fire hazard can be removed by eli minating oil: this can be achieved by the use of low flammability or fire-resistant fluid, or by the elimination of fluid altogether and making them air cooled. Whatever the method employed, and the merits of
FIG. 3.51 Two-unit nuclear station: 11/3.3 kV and 3.3/0.415 kV transformers located between reactor and turbine buildings
the alternative systems available are discussed in Sec-
tion 2.4 of this chapter, the purpose is to enable the transformers to be located indoors within switchrooms. These can thereby be placed very near to, or even integral with, LV switchgear, thus eliminating LV cabling. The benefits from this are considerable and are discussed further in Section 2.4.
1.7 Quality assurance and testing t7.1 Quality assurance (QA)
Unlike many items of power station electrical plant (for example, switchgear and motors) most transformers are virtually handmade, little or no mass production is employed in manufacture and each is produced very 243
Transformers much as a one-off. This means that the user cannot rely on extensive type testing of pre-production prototypes to satisfy himself that the design and manufacture renders the transformer fit for service, but must have such proving as is considered necessary carried out on the transformer itself. From a series of works tests, which might at most be spread over a few days, it is necessary to ascertain that the transformer will be suitable for thirty years or more in service. It is therefore logical that this testing should be complemented by a system of QA procedures which operate on each individual unit and throughout the whole design and manufacturing process. Details of operation of QA systems are beyond the scope of this volume and anyway these are covered adequately elsewhere, for example, by BS5750 [8], but it must be pointed out that testing alone will not demonstrate that the transformer is fully compliant with all the requirements which must be placed upon it. 1.7.2 Tests during manufacture
As part of the manufacturer's QA system, and also to meet the requirements of the specification, some testing will of necessity be carried out during manufacture and it will be appropriate to consider the most important of these in some detail. These are:
Core-plate checks Incoming core plate is checked for thickness and quality of insulation covering. A sample of the material is cut and built up into a small loop (Epstein Square) on which a measurement of specific loss can be made. Core-frame insulation resistance This is checked by megger and by application of a 2 kV RMS or 3 kV DC test voltage on completion of erection of the core, and again following replacement of top yoke after fitting the windings. Core-loss measurement If there are any novel features associated with the core design or if the manufacturer has any other reason to doubt whether the guaranteed core loss will be achieved, then this can be measured by the application of temporary turns to allow the core to be excited at normal flux density before the windings are fitted. Winding copper checks If continuously-transposed conductor (see Section 1.4.6 of this chapter) is to be used for any of the windings, strand-to-strand checks of the enamel insulation are carried out directly the conductor is received in the works. Tank tests The first tank of any new design is checked for stiffness and vacuum-withstand capability. For 275 and 400 kV transformers, a vacuum equivalent to 244
Chapter 3 to 25 mbar absolute pressure is applied. This need only be held long enough to take the necessary readings and verify that the vacuum is indeed being held, which might take up to 2 hours for a large tank. After release of the vacuum, the permanent deflection of the tank sides is measured and must not exceed specified limits of up to 13 mm, depending on length. Following this test, a further test is carried out at a pressure equivalent to 3 mbar absolute for 8 hours for the purpose of checking mechanical-withstand capability. Wherever practicable, tanks are checked for leaktightness by filling with a fluid of lower viscosity than transformer oil, usually white spirit, and applying a pressure of 700 mbar, or the normal pressure plus 350 mbar, whichever is the greater, for 24 hours. All welds are painted for this test with a flat white paint which aids detection of any leaks. 1.7.3 Processing and dry-out
The build-up towards the final works testing of a large power station transformer commences some time before it actually enters the test bay, at the stage at which the final processing and dry-out begins. Paper insulation and pressboard material, which make up a significant proportion by volume of the transformer findings, absorb large amounts of moisture from the atmosphere. The presence of this moisture brings about a reduction in dielectric strength and also an increase in volume. This increase in volume is such that, until the windings have been given an initial dry-out, it is impossible to reduce their length sufficiently to fit them on to the leg of the core and to fit the top yoke in place. The final drying-out is commenced either when the core and windings are placed in an autoclave or when they are fitted into their tank, all main connections made, and the tank placed in an oven and connected to the drying system. The tapping switch may be fitted at this stage, or later, depending on the ability of the tap switch components to withstand the drying process. Traditional methods of drying-out involve heating the windings and insulation to between 85 ° and 120 ° C, circulating dry air and finally applying a vacuum to complete the removal of water vapour and air from the interstices of the paper before admitting oil to cover the windings. For a small transformer operating at up to, say, 11 kV, this heating could be carried out by placing the complete unit in a steam or gas-heated oven. For a large transformer this process would take several days, or even weeks, so that nowadays the preference is to use a vapour phase heating system in which a liquid, such as white spirit, is heated and admitted to the transformer tank under low pressure as vapour. This condenses on the core and windings, and as it does so, releases its latent heat of vaporisation, thus causing the tank internals to be rapidly heated. It is necessary to ensure that the insulation does not exceed a • temperature of about 130 ° C to prevent ageing damage: -
General design and construction when this temperature is reached, the white spirit and water vapour is pumped off. Finally, a vacuum equivalent of between 0.2 and 0.5 mbar absolute pressure is applied to the tank to complete removal of all air and vapours. During this phase, it is necessary to supply further heat to provide the latent heat of vaporisation; this is usually done by heating coils in an autoclave, or by circulating hot air around the tank v,ithin the dry-out oven. The vapou- phase dry-out process is similar to systems used previously, the only difference being in the use of the vapour to reduce the heating time. it is not a certain method of achieving a drier transformer and, in fact, it is possible that the drying of large masses of insulation might be less efficient since, being limited by the rate of diffusion of water through the material, it is a process which cannot be speeded up. This is an area where further research might be beneficial. The other aspect of this system of dryingout which requires special attention is that of the compatibility of the transformer components with the heat transfer medium. For example, prior to the use of the vapour phase process, some nylon materials were used for transformer internals, notably in a type of self-locking nut. This nylon is attacked by hot white spirit, so it was necessary to find an alternative. Monitoring insulation dryness during processing usually involves measurement of some parameter which
9
C ' '
121'
1 311
is directly dependent on moisture content. Insulation resistance or power factor would meet this requirement. Since there are no absolute values of these which can be applied to all transformers, it is usual to plot readings graphically and dry-out is taken to be completed when a levelling out of power factor and a sharp rise in insulation resistance is observed. Figure 3.52 shows typical insulation resistance and power factor curves obtained during a dry-out. Vacuum is applied when the initial reduction in the rate-of-change of these parameters is noted: the ability to achieve and maintain the required vacuum, coupled with a reduction and levelling-out of the quantity of water removed and supported by the indication given by monitoring of the above parameters, will confirm that the required dryness is being reached. For a vapour phase drying system, since it could be dangerous to monitor electrical parameters, drying termination is identified by monitoring water condensate in the vacuum pumping system. At this point oil filling is begun with dry, filtered, degassed oil at a temperature of about 75 ° C being slowly admitted to the tank and at such a rate as to allow the vacuum already applied to be maintained. Drying-out of insulation is accompanied by significant shrinkage, so it is usual practice for a large transformer to be de-tanked immediately following initial oil impregnation to allow for retightening of all windings, as well as cleats and clamps on all leads and
1 16 11 DATE
Flo. 3.52 Insulation resistance and power factor curves during dry-out 245
Transformers
Chapter 3
insulation materials. This operation is carried out as quickly as possible in order to reduce the time for which windings are exposed to the atmosphere. However, once they have been impregnated with oil, their tendency to absorb moisture is considerably reduced so that, provided the transformer is not out of its tank for more than about twenty-four hours, it is not necessary to repeat the dry-out process. On returning the core and windings to the tank, the manufacturer will probably have a rule which says that vacuum should be applied for a time equal to that for which they were uncovered, before refilling with hot, filtered, degassed oil. Before commencement of final works tests, the transformer is then usually left to stand for several days to allow the oil to permeate the insulation fully and any remaining air bubbles to become absorbed by the oil. 1.7.4 Final testing Standard CEGB transformer test requirements are set out in BEBS T2 (1966). For the convenience of the reader the information is repeated in Tables 3.1 and 3.2.
Final works tests for a transformer fall into three categories:
• Tests to prove that the transformer has been built correctly These include ratio, polarity, resistance, and tapchange operation. • Tests to prove guarantees These are losses, impedance, temperature rise, noise level. • Tests to prove that the transformer will be satisfactory in service for at least thirty years The tests in this category are the most important and the most difficult to frame: they include all the dielectric or overvoltage tests, and load current runs. Full details of all tests in the first two categories above can be found in BS171 and are described at length in most standard textbooks. What is more, the tests themselves are logical and the outcome is beyond discussion. This section is concerned only with those tests included in the third category and aims to examine how the customer can best be satisfied that the transformer which he is buying has a reasonable chance of meeting the demands placed upon it for a lifetime in service.
TABLE 3.1 Summary of final works testing for generator, station and unit transformers
(a)
Tests to prove correct manufacture
Winding resistances Phasor group Voltage ratio Polarity Tapchange operation * Insulation resistances *
(b)
Tests to prove guarantees
BS 171 1970 Clause 40 BS 171 1970 Clause 40 BS 171 1970 Clause 39 BS 171 1970 Clause 38 BS 171 1970 Clause 48 I EC 551 I EC 551 BS 171 1970 Clause 41
Tests to prove 'quality'
Load current run * Induced overvoltage including partial discharge measurement Applied voltage Additional voltage * Switching surge voltage * I mpulse voltage including chopped waves
246
BS 171 1970 Clause 36 BS 171 1970 Clause 37 BS 171 1970 Clause 37 BS 171 1970 Clause 37
Generator and station transformers only
No load loss Magnetising current Load loss I mpedances Zero sequence impedance Transformer noise level Cooler noise level Temperature rise (c)
Test defined in
13EBS T2 Section 1 BS 171 1970 Clause 43 and BEBS T2 BS 171 1970 Clause 44 BEBS T2 Section I BS 171 1970 Clause 46
Routine test (R) Type test (T)
General design and construction TABLE 3.2 Summary of final works testing for auxiliary transformers
(a)
Tests to prove correct manufacture
Test defined in
Routine test (R) Type test (T)
13S 171 1970 Clause 36 BS 171 1970 Clause 37 BS 171 1970 Clause 37 BS 171 1970 Clause 37
Winding resistances Phasor group Voltage ratio Polarity Tapchange operation (if fitted) insulation resistances
(b)
Tests to prove guarantees
No-load loss Magnetising current Load loss I mpedances Transformer noise level Temperature rise 415 V busbar tests# (c)
BS 171 1970 Clause 40 BS 171 1970 Clause 40 BS 171 1970 Clause 39 BS 171 1970 Clause 38 I EC 551 BS 171 1970 Clause 41
Tests to prove 'quality'
Induced overvoltaee including partial discharge measurements Applied voltage I mpulse voltage including chopped waves
BS 171 1970 Clause 43 BS 171 1970 Clause 44 BS 171 1970 Clause 46
# AN transformers only
To do this, it is reasonable to start by considering how the transformer is likely to fail. There are, of course, many failure mechanisms for something as complex as a large transformer, but it is likely that these will fall into one of three classes: • Insulation will break down under the influence of the applied voltage stress. • Insulation will be prematurely aged, due to overheating. • Windings will suffer mechanical failure, due to inability to withstand the applied forces. Since failure mechanisms are complex, any particular failure might even be difficult to classify, being possibly due to a combination of more than one of the above causes. Overheating, for example, especially if not too severe, often will not itself cause failure, but will reduce the mechanical strength of the insulation, so that when the transformer is subjected to some mechanical shock, such as a system fault close to its terminals, it v, ill then fail. It is possible, too, that inadequate mechanical strength which allows movement of conductors could cause the reduction of electrical clearances so that it is electrical breakdown which causes failure. Even though failure modes are not always straightforward, the suggested classification allows objective discussion of appropriate methods of testing.
T*
*Routine on A N transformers
1.7.5 Power frequency oyeryoltage tests The traditional approach towards demonstrating that insulation will not be broken down by the applied voltage has been to apply a test voltage which is very much greater than that likely to be seen in service. This is the philosophy behind the overpotential test, which involves the application of twice normal voltage. Traditionally this was applied for one minute, but BS171 (1978) now allows this to be for a period of 120 times the rated frequency divided by the test frequency (in seconds), or 15 s, whichever is the greater. The test frequency is increased to at least twice the nominal frequency for the transformer to avoid overfluxing of the core and is often of the order of 400 Hz, so that test times of fifteen to twenty seconds are the norm. The test is thought by many to be a very crude one akin to striking a test specimen with a very large hammer and observing whether or not it breaks. Considerable effort has therefore been applied in recent ti mes to improving this test and this has largely been brought about by the introduction of partial-discharge measurements during the application of the overvoltage. Long before the total failure of transformer insulation occurs during overpotential conditions, minute discharge currents will flow. These tend to be triggered at the same point of successive cycles of the applied test frequency voltage waveform and to appear as pulses of high frequency disturbance in the band. Suitable detection equipment can be coupled to the winding 247
Chapter 3
Transformers under test, usually via the test tapping of the transformer bushing, and the disturbances can . either be displayed on an oscilloscope or measured directly on a voltmeter designed for radio interference voltage measurement. A measure of the peak value of the discharge can be obtained on the oscilloscope by comparison with the signal obtained by injection of a known pulse into the detector. Very occasionally, partial-discharge measurements made in this way can give a warning preceding total failure and the test voltage can be removed before complete breakdown, thus avoiding extensive damage. More often, however, the diagnosis is less clear-cut. It could be that measurements taken as the test voltage is being reduced indicate a tendency towards hysteresis, i.e., the discharge values for falling voltage tend to be greater than those obtained as the voltage is being increased. This could indicate that application of the test voltage has caused damage. It is CEGB practice to specify that, as the overvoltage is reduced, the discharge should fall to a nominal level (usually 100 picocoulombs) at an adequate margin above the normal working voltage, say, 1.2 p.u.V. There is a viewpoint in some international circles that, because of the extra refinement which partialdischarge measurement has brought to overpotential testing, it is no longer necessary to use a test voltage as severe as twice normal volts. This view has led to the method of overpotential testing detailed in IEC 76-3, Clause 11.4, Method 2 [9]. In this test, a voltage of 1.3 or 1.5 p.u.V is applied for 5 minutes. This is then raised to J3 p.u.V for 5 s followed by a return to 1.3 or 1.5 p.u.V which is then held for thirty minutes. Partial-discharge is recorded throughout the test and a close watch made for signs of any tendency for this to increase or run away during the test period. The choice between 1.3 and 1.5 p.u.V for the major proportion of the test time is to be agreed between manufacturer and purchaser. If the figure of 1.3 p.u.V is applied, then the partial-discharge shall not exceed 300 pC; if 1.5 p.u.V is used, then the value should not exceed 500 pC. Whilst it is clear that some constructive thought has gone into the framing of this test, it is the CEGB view that the degree of overpotential is too modest and it is not proposed to replace the 'twice normal voltage' test in CEGB specifications. A further point to be noted is that, whilst the induced overvoltage test is usually thought of as a 'twice normal voltage' test, for very high voltage transformers, it can be even more severe than this. Figure 3.53 shows the arrangement for carrying out the induced overvoltage test on a 400 kV transformer having graded insulation on the star-connected HV winding and a delta-connected LV winding. The test supply is taken from a single-phase generator connected to each phase of the LV in turn. The diagram shows the arrangement for testing phase A. In accordance with BS171, 1978, Clause 20 and Table 8, a voltage of 630 kV to earth 248
315kV
- 315kV
A • 630kV
+28.9kV
2
2 -28.9kV
630 kV TO EARTH INDUCED IN A PHASE UNE TERMINAL 945kV INDUCED BETWEEN A & B PHASE TERMINALS FIG. 3.53 Arrangement of induced overvoltaee test on a three-phase star/delta 400/23.5 kV generator transformer
must be induced at the line terminal. BS171 does not specify on which tapping the transformer should be connected and so the manufacturer usually opts for position 1 which corresponds to maximum turns in circuit in the [-IV winding. This might be the +6.66% tap for a generator transformer, which could correspond to 460.5 kV for a transformer having an opencircuit voltage of 432 kV on the principal tap. This is the line voltage, so the phase voltage appropriate to position 1 is 460.5/V3 = 265.8 kV: the test voltage of 630 kV induced in this winding therefore represents 2.37 times the normal volts/turn. It will be seen from Fig 3.53 that during the induced overvoltage test, although all parts of the windings experience a voltage of more than twice that which normally appears between them, that section of the winding which is nearest to earth is not subjected to a very high voltage to earth. This is so even for fullyinsulated windings which, when tested, must have some point tied to earth. It is therefore necessary to carry out a test of the insulation to earth (usually termed 'major insulation' to distinguish this from interturn insulation) and, for a fully-insulated winding, this is usually tested at about twice normal volts. For a winding having graded insulation, the test is at some nominal voltage; for example, for 400, 275 and 132 kV transformers, it is specified as 45 kV in BEBS T2 (1966), Section 1 [10]. In addition to partial-discharge measurement, another diagnostic technique to detect incipient failure
General design and construction has made progress in recent years: this is the detection and analysis of dissolved gases in transformer oil. When partial-discharee or flashover or excessive heating takes place in transformer oil, the oil breaks down into hydrocarbon eases. The actual gases produced and their relative ratios are dependent on the temperature reached. This forms the basis of the dissolvedas analysis technique which originally found use as a tool to assist in the diagnosis of faults in service. When faults occur during works tests, the volumes of the gases produced are very small and these diffuse through very large quantities of oil. Although the starting condition of the oil is known and its purity is very high, very careful sampling and accurate analysis of the oil is necessary to detect these gases. Analysis is assisted if the time for the test can be made as long as possible, and this was the philosophy behind the three-hour overpotential test which was introduced by the CEGB in the early 1970s. It must be emphasised hat this test is carried out in addition to the 'twice normal volts' test. 130% of normal volts is induced for a period of three hours. In order that the magnetic circuit, as well as the windings, receives some degree of overstressing, the test frequency is increased only to 60 Hz rather than the 65 Hz which would be necessary to prevent any overfluxing of the core. Partial-discharge levels are monitored throughout the three hours. Oil samples for dissolved-gas analysis are taken before the test, at the midway stage and at the conclusion. g
1.7.6 Impulse tests Mention was made in Section 1.4.10 of this chapter that a power station transformer in service will, from time
to time, be subjected to surges caused by lightning or by switching, and that the effect of these on the transformer windings is different from the effects of power frequency voltages. The impulse test was devised as a si mulation of a lightning strike on the line near to the connection to the transformer and to test the performance of the transformer in response to this risk. A standard impulse wave is defined in BSI71 and is illustrated diagrammatically in Fig 3.54. It has a front ti me of 1.2 As and a time to decay to half-peak of 50 its. A tolerance of +30% is allowed on the front ti me and +20% for the time to half-peak. In addition to these standard impulses, choppedvave tests may be specified which simulate the condition of a flashover of an external co-ordinating gap close to th,e terminals of the transformer. For these, a rod gap or some similar device is placed across the transformer test connection and earth. The size of the gap is such that it flashes over as the impulse wave reaches its peak. This causes a very rapid collapse of the voltage applied to the transformer windings, which results in a very rapid rate-of-change of voltage and high electrical stress in the windings. I mpulse tests are regarded in BS17I as type tests, i.e., they are carried out on the first transformer of
T, DURATION OF WAVEFRONT 1 67 TIMES THE INTERVAL BETWEEN 30% AND 90% OF THE PEAK VALUE T TIME TO HALF VALUE = THE INTERVAL BETWEEN THE ORIGIN 0 AND 0 AND THE 50% PEAK
ei
ui (.1
1
PEAK TIME TO ORESTI 4 .41-11.1
FIG. 3.54
TAIL •
Standard i mpulse wave
a new design as a means of demonstrating that this has correctly incorporated the necessary features to withstand the stresses produced under surge conditions. However, in addition, they are now regarded by the CEGB as a very searching check of quality which can provide further information to assist in proving that each transformer will be suitable for its defined service lifetime. Impulse tests, including chopped waves, are therefore specified for all windings of all power station transformers having operating voltages of 3.3 kV and above. A standard CEGB transformer specification would therefore call for an impulse test consisting of seven shots, as follows: I — Reduced full-wave 1 — 100% full-wave 2 — 115% chopped-waves 2 — 100% full-waves — Reduced full-wave It is assumed that the first full-wave shot, at about 75% of the nominal full-wave impulse test level, will not break down the transformer and so the voltage and current records of that shot are taken as the reference standard. Assessment as to whether the transformer has passed or failed is basically made by com07 paring the records for the final 75 w reduced fullwave with those for the initial one. Chopping of the chopped-wave shots is specified to take place between 2 and 6 its from the start of the wave. The amplitude is increased to 115% of the specified full-wave level in order to ensure that the voltage is at least 100% of the specified level at the instant of chop. 249
Transformers I mpulse tests differ from power frequency tests in that, although very large test currents flow, they do so only for a very short time. The power level is therefore quite low and the damage done in the event of a failure is relatively slight. If a manufacturer suspects that a transformer has a fault, say from the measurement of high partialdischarge during the overpotential test, he may prefer to withdraw the transformer from this test and apply an impulse test which will produce a less damaging breakdown. On the other hand, the very fact that damage tends to be slight can make the location of an impulse test failure exceedingly difficult. Diagnosis of impulse test failures can themselves be difficult, since sometimes only very slight changes in the record traces are produced. For further information on impulse testing and diagnosis techniques the reader is referred to the Electricity Councils 'Guide on Impulse Voltage Testing Power Transformer and Reactors [111' or any other standard textbook on the subject. 1.7.7 Switching-surge tests
Surges generated by lightning strikes have very steep rise-times which cause transformer windings to appear as a string of distributed capacitance rather than the inductance which is presented to a power frequency voltage. Surges generated by system switching do not have such rapid rise-times — times of 20 its are typical — and at this frequency the transformer winding behaves much as it would do at 50 Hz. The voltage is evenly distributed, flux is established in the core and voltages are induced in other windings in proportion to the turns ratio. The magnitude of switching surges, though generally lower than lightning surges, is considerably greater than the normal system voltage (perhaps 1.5 times or twice), so that the overpotential test is not an adequate test for this condition. Switching-surge tests are therefore carried out on all transformers which might be subjected to switching surges in service. Three shots are carried out at a level equivalent to 80% of the full-wave impulse test level, with a waveshape having a front time of 20 as and a tail of at least 480 as. 1.7.8 Load runs
The second possible mode of transformer failure listed in Section 1,7.4 of this chapter, is premature ageing of insulation due to overheating. It is therefore important that the opportunity is taken to investigate the thermal performance of the transformer during works testing as fully as possible, in an attempt to try to ensure that no overheating will be present during the normal service operating condition. Conventional temperature rise tests, for example, in accordance with BS171, are less than ideal in two respects: 250
Chapter 3 • They only measure average temperature rises of oil and windings. • By reducing the cooling during the heat-up period, manufacturers can shorten the time for the test to as little as eight or ten hours. Such tests will have little chance of identifying localised hot spots which might be due to a concentration of leakage flux or an area of the winding which has been starved of cooling oil. The CEGB apprOach to searching out such possible problems is to subject the transformer to a run during which it will carry a modest degree of overcurrent for about thirty hours. The test is specified as a period at 110% full-load current, or a current equivalent to full-load losses supplied, whichever is the greater, for twelve hours at each extreme tap position, with each twelve hours commencing from the time at which it reaches normal working temperature. Also, during this load-current run, the opportunity can be taken to monitor tank temperatures, particularly in the vicinity of heavy flanges, cable boxes and bushing pockets, and heavy current bushings. Both extremes of the tapping range are specified since the leakage flux pattern, and therefore the stray loss pattern, is likely to vary with the amount of tapping winding in circuit. Oil samples for dissolved-gas analysis are taken before the test and at the conclusion of each twelve-hour run. If the transformer is the first of a new design, then gradients and top oil and resistance rises are measured in accordance with BS171. However, the main purpose of the test is not to check the guarantees but to uncover evidence of any localised overheating should this exist. 1.7.9 Short-circuit testing
It is in relation to short-circuit performance and the demonstration that a transformer has adequate mechanical strength that the customer is in the weakest position. Section 1.4.12 of this chapter described the nature of the mechanical short-circuit forces and made an estimate of their magnitude. However, for all but the smallest transformers, the performance of practical tests is impossible due to the enormous rating of test plant that would be required. IEC 76-5 [9), deals with the subject of ability to withstand both thermal and mechanical effects of short-circuit. This it does under the separate headings of thermal and dynamic ability. For thermal ability, the method of deriving the RMS value of the symmetrical short-circuit current is defined, as is the time for which this is required to be carried, and the maximum permissible value of average winding temperature permitted after shortcircuit (dependent on the insulation class). The method of calculating this temperature for a given transformer is also defined. Thus this requirement is proved entirely by calculation.
General design and construction For the latter, it is stated that the dynamic ability to withstand short-circuit can only be demonstrated by testing; however, it is acknowledged that transformers over 40 MVA cannot normally be tested. A procedure for testing transformers below this rating involving the actual application of a short-circuit is described. Oscillographic records of voltage and current are taken for each application of the short-circuit and the assessment of the test results involves an examination of these, as well as an examination of the core and windITPS after removal from the tank. The Buchholz relay, if fitted, is checked for any gas collection. Final assessment on whether the test has been withstood is based on a comparison of impedance measurements taken before and after the tests. It is suggested that a change 0 of more than 2 Io in the measured values of impedance are indicative of possible failure. This leaves a large group of transformers which cannot be tested. Although this is not very satisfactory, service experience with these larger transformers over a considerable period of time has tended to confirm that design calculations of the type described in Section 1.4.12 of this chapter are producing fairly accurate results. Careful examination of service failures of large transformers, especially where there may be a suspicion that short-circuits have occurred close to the transformer terminals, can yield valuable information concerning mechanical strength as well as highlighting specific weaknesses and giving indication where weaknesses may be expected in other similar designs of transformer. On occasions, such an approach has enabled incipient failures to be identified from internal inspections made during a planned outage before these have caused catastrophic failures which would have resulted in extensive damage as well as unscheduled loss of generation.
1.8 Transport, installation and commissioning 1.8.1 Transport The generator transformer is usually one of the three largest and heaviest single loads to be delivered to a power station site. (The other two being the generator stator and the stator frame.) Transport considerations will therefore have a considerable bearing on the generator transformer design and more will be said on this subject in Section 2.2 of this chapter which deals specifically with generator transformers. For the other large transformers (station and unit transformers), it is usually only necessary to ship these without oil to ensure that they are comfortably within the appropriate transport limits, although it is necessary to check that when mounted on the transport vehicle the height is within the over-bridge clearances which, for trunk roads within the United Kingdom, allows a maximum travelling height of 4.87 m (sixteen feet).
If the tank has been drained for transport, it is necessary for the oil to be replaced by either dry air or nitrogen, which must then be maintained at a slight positive pressure above the outside atmosphere to ensure that the windings remain as dry as possible whilst the oil is absent. This is usually arranged by fitting a high pressure gas cylinder with a reducing valve to one of the tank filter valves and setting this to produce a slow gas-flow sufficient to make good the leakage from the tank flanges. A spare cylinder is usually carried to ensure continuity of supply should the first cylinder become exhausted. Transporters for the larger transformers consist of t wo beams which span front and rear bogies and allow the tank to sit between them resting on platforms which project from the sides of the tank. Thus the maximum travelling height is the height of the tank itself plus the necessary ground clearance (usually taken to be 75 mm but capable of reduction for low bridges). Figure 3.55 shows a 267 MVA single-phase transformer arranged for transport. Smaller transformers, i.e., auxiliary transformers of maximum rating 12.5 MVA, can usually be shipped completely erected and full of oil, 1.8.2 Installation and site erection In view of their size and weight, most transformers present special handling problems on site. The manufacturer in his works will have crane capacity, possibly capable of lifting up to 260 t based on transport weight limit including vehicle of 400 t, but on-site such lifts are out of the question except in the turbine or reactor hall. Site handling is difficult and must be restricted to the absolute minimum. The transformer plinth therefore should be completed and clear access available, allowing the main tank to be placed directly onto it when it arrives on site. The access road must also be completed, as well as the surface over any space between access road and plinth. Transformer and vehicle can then be brought to a position adjacent to the plinth. The load is then taken on jacks and the transport beams removed. Then, using a system of packers and jacks, the tank is lowered onto a pair of greased rails along which it can be slid to its position over the plinth. The required position of tank on the plinth must be accurately marked, particularly if the transformer is to mate up with metalclad connections on either the LV or HV side. When the tank is correctly positioned on the plinth, the coolers and pipework are installed. Bushings and turrets which have been removed for transport are fitted and connected, requiring the removal of blanking plates giving access to the tank. Such opening of the tank must be kept to a minimum time, to reduce the possibility of moisture entering the tank; to assist in this, manufacturers of large high voltage transformers provide equipment to blow dry-air into the tank and thus maintain a positive internal pressure. 251
Chapter 3
Transformers
ON ;LOAD ',VE 5, 7 :id 'ONNES
I jor•LAL GROUND CLEARANCE
Fic, 3.55 Transport arrangements for a 267 MVA single-phase generator transformer
If the transformer has been transported with the tank full of nitrogen, it is necessary to purge this fully with dry air if anyone has to enter the tank. When all bushings have been fitted, access covers replaced, and conservator and Buchholz pipework erected, preparations can begin for filling with oil. Even if the transformer is not required for service for some months, it is desirable that it should be filled with oil as soon as possible and certainly within three months of the original date of draining the oil. If it is being kept in storage for a period longer than three months, it should similarly be filled with oil. After completion of site erection, a vacuum pump' is applied to the tank and the air exhausted until a vacuum equivalent to between 5 and 10 mbar can be maintained. Heated, degassed and filtered oil is then slowly admitted to the bottom of the tank in the same way as was done in the works, until the tank is full. Since, despite all the precautions taken, some moisture will undoubtedly have entered the tank during site erection, the oil must then be circulated, heated and filtered until a moisture content of around 2 PPM by volume is achieved for a 400 or 275 kV transformer. For a unit transformer having a high voltage of 23.5 kV, a figure of around 10 PPM is acceptable. If the transformer has been stored on its plinth full of oil, it will also be necessary to erect the cooler and pipework and fill this with oil before it can go into service. Initially, the cooler will be filled with the main tank isolating valves closed and oil will be circulated via a tank by-pass pipe to dislodge any small bubbles of air which can be vented via the cooler vent plugs. Normally, such tank by-passes are installed by manufacturers as a temporary fitment but it is now CEGB practice to retain them as permanent features on large generator transformers. The oil necessary to bring the level up to minimum operating level can then be added via the conservator filling valve and, once the conservator is brought into operation, the refrigeration 252
breather may be commissioned for transformers of 132 kV and above. This needs an auxiliary power supply which should, if necessary, be supplied from site supplies, so that the breather can be made alive without waiting for the marshalling kiosk to be installed and energised. 1.8.3 • Site commissioning
Transport to site could well have involved a journey of many hundreds of miles, part possibly by sea. The transformer will have had at least two lots of handling. There is, however, very little testing which can be done at site which can demonstrate that it has not suffered damage. It is therefore vital that such testing as can be carried out at site should be done as thoroughly and as carefully as possible. The following should be carried out as a minimum: • Ratio measurement on all taps. • Phasor group check. • Winding resistance measurements on all taps. • Operation of tapchanger up and down its range. Check the continuity of tapped winding throughout the operation. • Insulation resistance between all windings and each winding to earth. Insulation resistance core-to-earth, core-to-frame and core frame-to-earth. • No-load current measurement at reduced voltage; very likely this will be done at 415 V and compared with the current obtained at the same voltage in the works. • Oil samples taken and checked for breakdown strength and moisture content. For a generator transformer for which the oil is to be tested quarterly for dissolved-gas content, this sample would also
Special design features be checked for gas content and taken as the starting point. • M1 control, alarms, protection and cooler gear checked for correct operation. Protection trips set to appropriate level for initial energisation. • Tank and cooler earth connections checked as well as the earthing of the HV neutral, if appropriate.
There are also a number of other criteria which although less important will also have a bearing on the design. These are: • Because of the high load-factor, both load and no-load losses must be as low as possible. • In view of the direct connection to the 400 kV system. a high impulse strength is required. • Noise level must be kept below a specified level.
2 Special design features whilst the foregoing sections have examined those features which most power station transformers have in common, the following sections take a closer look at each class of transformer to examine those aspects which are special for its particular duty.
2,1 Generator transformers 2.1.1 Required characteristics
The generator transformers, in most present day stations will have a voltage ratio of 23.5/400 kV. The rating must be sufficient to allow the generator to export its full megawatt output at 0.85 power-factor lagging or 0.95 power-factor leading or, alternatively, half of full megawatt output at 0.7 power-factor lead. Some early 660 MW generators were designed to deliver full output at 0.8 power-factor which, making due allowance for the power requirements of the unit board, led to a maximum output power of 800 MVA so that for the sake of standardisation the generator transformer rating has been fixed at this level. The important criteria which influence the generator transformer design are as follows:
• Very little overload capability is necessary. A figure of 4% overload for three one-hour periods per day is normally specified. 2.1.2 General design features
The extensive list of required characteristics given above places considerable constraints on the design of the generator transformer. For a transformer of 800 MVA, 400 kV, the most limiting factor is that of transport weight. The high HV voltage requires large internal clearances which means increasing size and, as can be seen from the expression for leakage reactance in Section 1.3.2. of this chapter, increased HV to LV clearance has the effect of increasing the reactance, and hence the impedance. This tendency to increase reactance would normally be offset by an increase in the axial length of the winding but, for a large generator transformer, the stage is soon reached where further increases cannot be obtained because of the limit on transport height. A significant reduction in leakage reactance for given physical dimensions can be obtained by adopting an arrangement of windings known as 'split-concentric'. This is shown in Fig 3.56 (a). The HV winding has
• The HV volts are high — usually 400 kV. • The LV current is high — almost 20 000 A for an 800 MVA transformer. INNER NV
• The impedance must be lower than that resulting from the simplest design for this rating — a figure of about 16% is specified and variation with tap position must be kept to a minimum to simplify system design and operation.
• The transport weight must be within the limits laid down by the transport authorities and the available transport vehicles. • Reliability and availability must be as high as possible, since without the generator transformer unit output cannot be made available to the national grid and the replacement generation cost of an outage is high.
OUTER NV
(a) Spill concenIrc winclog arrangement
LEAKAGE FL
• An on-load tapchanger is required to allow for variation of HV system volts and generator power factor. LV volts will remain within +5 070.
LV
STnple COncenInc windIng
Split.Concenl , c w-raIng
FIG. 3.56 Split-concentric winding arrangement
253
Transformers been split into two sections, with one placed on either side of the LV winding. This is not too inconvenient for .a transformer with graded HV insulation, since the inner HV winding is at lower potential and can therefore be insulated from the earthed core without undue difficulty. The reason why this arrangement reduces leakage reactance can be seen from Figs 3.56 (b) and (c), which (.ii‘e plots of leakage flux both for si mple concentric and split concentric arrangements having the same total MMF. It can be shown that the leakage reactance is proportional to the area below the leakage flux curve, which is significantly less in the split-concentric design. The price to be paid for this method of reducing the leakage reactance which, in reality, means reducing the physical size for a given rating, is the complexity involved in the increased number of windings, increased number of leads, and increased sets of interwinding insulation. For simplicity, the tapping winding has not been shown in Fig 3.56 (c). With this split-concentric arrangement, the taps are usually accommodated in a separate winding below the inner HV winding. As taps are added or removed, the ratio of the HV split is effectively varied and this has the effect of producing relatively large changes in leakage reactance. This undesirable feature is a further disadvantage of this form of construction. Throughout the 1960s, at the time of building most of the 500 MW units, the split-concentric arrangement was the most common form adopted for 570 MVA and 600 MVA three-phase generator transformers. It enabled these transformers to be transported threephase within limits of about 240 t transport weight and 4.87 m travelling height, albeit most of them had very high flux densities and losses in order to keep the material content to the minimum. In fact, a transformer of 735 MVA, three-phase, although its HV winding was only 275 kV, was transported within these li mits to Hartlepool power station. However, at the ti me of the adoption of the 660 MW unit size for Drax power station at the end of the 1960s, it was decided to make the transition to single-phase units. These have many advantages and will be described in greater detail in the following section. 2.1.3 Single-phase generator transformers
With the adoption of single-phase construction, transport weight for 800 MVA and probably even larger transformers ceases to impose any significant constraint on the transformer designer. Travelling height continues to impose some restriction, but the designer is usually able to deal with this without undue difficulty. Figure 3.57 shows various arrangements of core and windings that can be adopted for single-phase transformers. In Fig 3.57 (a), the core has one wound limb and two return yokes. Alternatively, both limbs could be wound, as shown in Fig 3.57 (b), but this increases the cost of the windings and also the overall height, since the yoke must be full-depth. It would be possible to 254
Chapter 3 reduce the yoke depth by providing two return yokes as in Fig 3.57 (c) but this adds further complexity and is therefore rarely advantageous. Some manufacturers reduce the yoke depth still further by using four return yokes (Fig 3.57 (d)). Figure 3.58 shows the core and windings of a CEGB single-phase 23.5/400 kV generator transformer having one limb wound and with four return yokes. This has a transport weight of 185 t and a travelling height of 4.89 m. The arrangement of Fig 3.57 (a) is also used for some CEGB single-phase generator transformers. A further benefit of single-phase construction is that should a failure occur, it is very likely to affect one phase only, so only that phase need be replaced and, being more easily transported, spare single-phase units can be kept at strategic central locations which can then serve a number of power stations. This led to the concept of interchangeable single-phase generator transformers which were developed for the majority of the 660 MW units. For this the electrical characteristics of impedance and voltage ratio must be closely matched on all tap positions and, of course, the physical sizes and arrangements of connections for HV and LV windings must be compatible. Each single-phase unit must have its own on-load tapchanger, driven from a single drive mechanism mounted at the end of the bank. Tapchangers must thus be compatible in that all must drive in the same sense and all must have the same number of turns for a tap change. The tapchangers must be located so that the drive shafts will align. The location of inlet and outlet cooling oil pipes must correspond on all units. Figure 3.59 shows the arrangement of an 800 MVA bank of single-phase units and details all the items which must align to provide complete interchangeability. Both ends of each winding of a single-phase unit are brought out of the tank so that the NV neutral has to be connected externally, as well as the LV delta. The former is arranged by bringing the earthy end of each HV winding to a bushing terminal mounted on the top of the tapchangers. These can then be solidly connected together by means of a length of copper bar, suitably connected to the station earth. On the early single-phase banks, the LV delta was connected by means of an oil-filled delta box which spanned the three tanks. This can be identified in Fig 3.59. It was split internally into three sections by means of barrier boards so that the oil circuits of the three tanks were kept separate. It was recognised that phase-to-phase faults were possible within the delta box and that greater security could be obtained by the use of an external air-insulated phase-isolated delta which was, in fact, an extension of the generator main connections. This is now the standard arrangement, so that the LV connections to each single-phase unit are made via a pair of bushings mounted on a pocket on the side of the transformer tank. The use of airinsulated phase-isolated delta connections has the added' advantage that it enables the oil circuits of the three
Special design features
HALF - DEPTH RETURN YOKE
la} Single mnding on centre limb
(b) Increase in height due to windings on both limbs
HALF - DEPTH • RETURN YOKE
(c) Height reduction by using two return yokes
(d) Further height reducton using tour return yokes and centre limb
FIG. 3.57 Core and windings for single-phase transformers
phases to be kept entirely separate, so that, in the event of a fault on one phase, there will be no contamination of the oil in the other phases. The HV connections may be via air bushings or
SF6-insulated metalclad trunking. The interface is therefore the mounting flange on the tank cover, as can be seen from Fig 3.59. Figure 3.60 shows an 800 MVA generator transformer bank installed at Drax power station before erection of the acoustic enclosure. 2,1.4 Performance and reliability The generator transformer is
the one transformer on
a power station for which no standby is provided. It must be available for the generator output to be connected to the grid. For a high merit unit, high reliability is required. If its output were lost, this would necessitate running less efficient plant which is more expensive to operate. It is difficult to set down design rules for high reliability. Design experience may identify features which might detract from reliability but it is difficult to be sure that every potential source of trouble has been avoided. Large generator transformers are produced in small numbers, so there are no large production runs which can be used to eliminate teething troubles. One factor which can aid reliability, therefore, is to 255
Chapter 3
Transformers
Flo. 3.58 Core and Nvindings of single-phase CEGB generator transformer (GEC Alsthom) (see also colour photograph between pp 496 and 497) 256
Special design features
= =.7
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41-
- -
5
/ DRIVE
2 807
SURFACE OF PLINTH
4 877
21fiNT S
5.296
a
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:2 ,
2 934 559 FLANGE DR ,
ED 10 55 'L lABE
.
-
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EXTERNAL tV CONNECTIONS FOR 96151 TRANSFORMER
900 c2
1 900 s s
UV 0.i. FL-LEO
OEL .FABOX SHOWN
020
R • At TERN
FIE., 3.59
52
E P AN FOR AR •NS'..:LATED DELTA CONNECTIONS
Details of 800 MVA bank of single-phase transformers showing requirements for interchangeability
repeat tried and proven designs wherever possible, even os.er many years, thus reducing the occasions on which
teething troubles might occur. Another design rule for high reliability is to 'keep it si mple'. This is not easy for an item as sophisticated as a large generator transformer but, nevertheless, as explained in Section 2.1.2 of this chapter, a degree of si mplification was achieved by the change from threephase to single-phase units. This also meant that there Nas no longer the same emphasis on keeping sizes and weights to an absolute minimum and so there vras a consequent relaxation of the pressures which threatened reliability . In view of the importance of high reliability of generator transformers, the CEGB gave special attention to the subject in the 1970s in the light of op-
erating experience on the 570 and 600 MVA units following a series of failures. It was recognised that the occurrence of teething troubles on new designs was having a significant effect on the reliability of these units. Study of the operating failures showed that reliability was likely to be poorer with new designs during their early life. Furthermore, design changes tended to be introduced frequently due to the practice of designing for lowest total cost taking into account the changing cost of losses (see Section 2.1.5 of this chapter). It was decided that, although it was not possible to have long production runs which might eliminate the teething troubles associated with new designs, it was possible to limit the number of new designs which were introduced, particularly since a single standard rating of generator of 660 MW had 257
(Lot- pup 96i, (AI r. ILUOLOS[V
•
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,
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.
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Special design features been adopted. Accordingly in 1979, the CEGB introduced the concept of Registered Designs whereby manu-
facturers agreed that they would submit detailed technical parameters and schedules of all manufacturing d rz w.ines, including details of revision of issue, to describe their current design of 267 MVA 23.5/400 kV sinule-phase generator transformer, which should pre,. have been successfully tested and in operation :cr abl a CEGB )ower station. These particulars then at became that n anufacturer's registered design particulars and, for future stations, changes to these would aril % be allowed if it could be demonstrated that a definite improvement in reliability would result, or ■ k.erc unavoidable due to the non-availability of some ten' required for manufacture. Design change in the interest of further competitiveness was not acceptable. After more than seven years of operating the re,istered design scheme, which has only been applied to his one rating of generator transformers, there are clear indications that these transformers are achieving a very much higher reliability than their predecessors. It cannot, of course, be claimed that this is solely due to the registered design system, since the other factors mentioned in this section, aS well as the more exten,,i% e testing procedures described in Section 1.7 of this chapter, are all likely to have contributed. The CEGB is aware of the possible consequences i mplied in the registered design procedure that designs inight become 'fossilised'. It is considered, however, that by allowing changes that can be shown to improve reliability, a mechanism for worthwhile development exists which will act as a safeguard against this. 2.1.5 Economics of operation II the generator of a high-merit unit is unavailable for any reason, making it necessary for less efficient plant to operate instead, then there will be extra costs to the system equal to the difference in operating costs for the failed and the replacement units. A major failure which necessitates the removal of a single-phase unit and the substitution of a spare would result in an outage of several weeks which could incur additi onal operating costs equal to the first cost of the Transformer. This helps the subject of reliability to be seen in context. There are, however, other costs associated with opation of a transformer. These may be considered on an annual basis and consist of:
necessary replacement generating capacity and a running cost which reflects the 'amount of energy consumed, i.e., having the form: EP [Ap + k (d/100) 8760]
(3.6)
where P = total losses, kW A = capacity charge, E/kW d = energy charge, pence/kWh k = factor which reflects the fact that the unit will not generate for 365 days/year and is about 0.72 p = an amortisation factor whose derivation is given below
Capital charges The purchase of a transformer involves the spending of money which either has to be borrowed or which could earn income, if invested. At the end of n years, the borrowed money has to be repaid or, alternatively, enough money will have to be saved to replace the asset. The amortisation factor p is given by: r 100
per £ of initial cost
r
(3.7)
100 where r Wo is the real rate of return on capital, i.e., the rate in excess of inflation. This is set as a target 'test discount rate' by the Government when economic policies for nationalised industries are appraised from ti me to time. Loss
assessment To assess whether it is justifiable to spend additional capital, £ AC, to reduce losses, it is necessary to show that: ACp
(3.8)
This can be illustrated by an example as follows: Capacity charge
E120/kW
Energy charge
2.4 pence/kWh
• Annual value of initial capital cost.
Test discount rate
10 07o
• Cost of power absorbed as losses.
Assumed plant life (n)
20 years
Annual availability factor (k)
0.72
C(isi of losses
Although not strictly accurate, it is assumed that whenever the generator 'transformer of a [nett merit unit is energised, it will operate at full-load. It is therefore necessary to supply iron losses, load losses and cooler losses in total. These have an annual cost based on the annual capital cost of installing the
From Equation (3.7) amortisation factor p is given by: 0.1 x
1.1 20 (1 . 120_
1)
= 0.1175 259
IP
Transformers
Chapter 3
A balance in Equation (3.8) occurs when
AC x 0.1175 = (120 x 0.1175) + (0.024 x 8760 x 0.72) i.e.,
£1408
caphahsed by costing them at a The losses figure of £1408 , kW and any expenditure greater than his for a saving of one kilowatt of loss cannot be justified. It should be noted that the numbers used in the above example have been provided for the purposes of illustration. Whilst at the present time they reflect with reasonable accuracy the values which would be actually used within generation construction, in times of high inflation they may change considerably. It might also be recognised, however, that the value of £1408/kW which has been derived, is considerably less than the figure which is used by many authorities even at the present time. The reason for this is the value of test discount rate used; it will be seen that if the above calculation is repeated with a value of test discount rate set at 5 070, a figure used by some authorities, a loss value of about £2000/kW will be deduced. The effect of the higher test discount rate, therefore, is to place a lower value on losses and to sway assessments towards acceptance of lower initial capital cost options. Further indication of the significance of the cost of losses can be gained by considering a specific transformer associated with a 600 MW unit. This might have total losses of 2 MW and a first cost of £2.5 million. Capitalising the losses at the figure of £1408/kW puts their value at £2.8 million; it can be seen that the saving from a reduction of a few per cent in losses is very significant. Because this calculation can be so easily performed, it is tempting for accountants to demand that it be carried out whenever the purchase of a new transformer is contemplated. In the 1960s, when energy and material costs as well as interest rates were changing rapidly, and by differing amounts in relation to each other, rapid changes in loss capitalisation values were common. This was one of the pressures for the introduction of new designs which were not warranted on purely technological grounds. Hence the CEGB introduced the registered design concept described in Section 2.1.4 of this chapter, and the decision was taken that a loss-capitalisation calculation would not be carried out as part of the tender assessment process for 800 MVA transformers so that manufacturers were not encouraged to change designs in the interests of Lompetitiveness. Since different manufacturer's designs did not actually have the same losses, the design having the highest losses might appear to have an unfair advantage, since it might be expected to contain least material. However, this was not considered to be significant for the variation in losses which occurred in
2 60
practice, and operation of the registered design procedure for a number of generator transformer tenders has supported this view.
2.2 Station transformers 2.2.1 Station transformer characteristics The station transformer supplies the power , station auxiliary system for starting-up the boiler/turbinegenerator unit and for supplying those loads which are not specifically associated with the generating unit, for example, lighting supplies, cranes, workshops and other services. In addition, in order to provide a diversity of supplies to certain plant, the station switchboard is used as a source of supply for certain large drives which are provided on a multiple basis for each unit, for example, the gas circulators of a nuclear reactor and the circulating water pumps for the main condensers. The station transformer is usually the first major connection with the grid for a power station under construction, providing supplies for the commissioning of the plant. The design criteria to be met by the station transformer are as follows: • The HV connection is from the 132, 275 or 400 kV grid system. • On the most recent, larger units, the LV is invariably 11 kV nominal. • Impedance must be such that it can be paralleled with the unit transformer at 1I kV without exceeding the permissible fault level usually about 15%. —
• An on-load tapchanger is required to maintain 11 kV
system volts constant as load is varied and as grid voltage varies. • Operating load-factor is low, i.e., for much of its life the station transformer will run at half-load, or less. Load losses can therefore be relatively high, but fixed losses should be as low as possible. 2.2.2 General design features As explained in Section 1.1.2 of this chapter, the station transformer is almost invariably star/star connected, since both HV and LV windings must provide a neutral for connection to earth. Until recently, such a transformer would automatically have been provided with a delta-connected tertiary for the elimination of third harmonic. However, as auxiliary systems and the transformers feeding them become larger, fault levels become greater, and at the ti me of designing the auxiliary system for Littlebrook D power station it became clear that the use of a 132/11 kV 60 MVA station transformer with a deltaconnected tertiary would create problems in the event
of single-phase-to-earth faults on the 11 kV system.
Special design features Such a transformer has an inherently low zero-sequence impedance and it is difficult for the designer to increase this whilst maintaining the positive-sequence impedance low enough to meet the required regulation performance. The solution appeared to be to omit the tertiary, but then concern arose as to whether this .,% ould result in the zero-sequence impedance becoming Huh that single-phase-to-earth faults on the II kV „ Te m v.[ou1. 1 not pass sufficient current to operate he protectior Consultations with transformer manufacturers suggested that this would not be so, since he transformo tank would behave as a very looselycoupled tertiary winding. This was confirmed by the works tests on the first transformer which showed that the zero-sequence impedance, measured on the t. V winding, was about six times the positive-sequence attic and was low enough to permit satisfactory operation of the protection. Although works testing showed that the actual value of zero-sequence impedance obtained by omitting the tertiary can be low enough to meet the auxiliary system protection requirements, it is necessary to ensure that the absence of a tertiary will not give rise to excessive third-harmonic currents circulating in the system neutral. Such currents flow whenever the system has more than one neutral, as in the example shown in Fig 3.61 where an auxiliary gas turbine generator with its neutral earthed is operated in parallel with the station transformer supply, thus setting up a complete loop for circulating currents. (The impedance of this loop to third-harmonic currents can be increased by connecting a third-harmonic suppressor in series with the gas turbine earth connection, see Section 2.5.6 • of this chapter.) Such a situation can exist at Littlebrook D and it was shown from site tests and calculations that the omission of the tertiary resulted in a three to four-fold increase in the third-harmonic current in The gas turbine neutral compared with systems which have a normal delta-connected tertiary on the station transformer. With an absolute value of no more than about t A in the transformer neutral, however, this was still considered to be acceptable. Without the gas
2,V SUB-STATION 7
GAS TURBINE GENERATOR
turbine connected in parallel, the station transformer neutral carried a third-harmonic current of less than 0.3 A. In order to ensure that protection problems are not encountered on future station transformers, it is now CEGB practice to specify that the zero-sequence impedance should fall within a band from 0.9 to 6 ti mes the positive-sequence value. Reference has been made in Section 1.5.1 of this chapter to the use of an on-load tapchanger on the station transformer as a means of compensating for grid voltage variation and for regulation within the transformer itself. This has an important bearing on the design of the station transformer. So that the 11 kV station board voltage remains at an adequate value under full-load conditions, the open-circuit ratio of the station transformer is selected to give a low voltage somewhat above nominal. A figure of 11.8 kV is typical. Under normal operating conditions the grid system voltage may be permitted to rise to a level l0°'0 above nominal. On the 400 kV system this condition is deemed to persist for no longer than 15 minutes. For the 132 kV and 275 kV systems, the condition ma), exist continuously. Should the station transformer HV volts rise above nominal, the operator may tap-up on the tapchanger, i.e., increase the number of turns in the HV winding. If the •HV voltage were to fall, he would operate the tapchanger in the opposite direction, which would reduce the HV turns: both these operations maintain the flux density constant. The operator can also use the tapchanger to boost the LV system voltage, either to- compensate for regulation or because a safe margin is required, say, to start an electric boiler feed pump. The tapchanger would increase the volts/turn and this would thus increase the flux density. The station transformer will probably have been provided with a tapping range of ± 10% to match the possible supply voltage variation. On the limit, it is possible for a voltage which is 10 07o high to be applied to the — 10% tapping. This is an oven, oltage factor of 22% and would result in an increase in flux density of this amount. To avoid saturation, it is desirable that the operating flux density should never exceed about 1.9 T; this results in a specified flux density of 1.55 T at nominal volts for all station transformers, a value considerably lower than that specified for other transformers, e.g., the generator transformer.
LIQUID EARTHING RESISTOR
2.3 Unit transformers Ikv STATION BOARD
EH_ 3.61
Connection of gas turbine neutral in parallel with station transformer neutral
2.3.1 Unit transformer characteristics
The unit transformer is teed-off from the main connections of the generator to the generator transformer It is energised only when the generator is in service 261
Transformers
Chapter 3
and supplies loads which are essential to the operation of the unit. The design criteria to be met by the unit transformer are as follows: • The H V voltage is 23.5 kV. • The LV voltage is invariably 11 kV nominal. • I mpedance must be such as to enable it to be paralleled with the station transformer at 11 kV without exceeding the permissible fault level — usually about 15 07a. • Since the HV voltage is maintained within +5 0/o of nominal by the action of the generator AVR, on-load tapchanging is not needed. • Operating load-factor is high, so that load losses and no-load losses will both be capitalised as the same rate. (Except in some nuclear stations, where two fully-rated unit transformers are provided per unit for system security purposes.) • Paralleling of unit and station transformers during changeover of station and unit supplies can result in a large circulating current between station and unit switchboards (Fig 3.62). This adds to the unit transformer load current, and subtracts from that of the station transformer. The unit transformer must therefore be capable of withstanding the resultant short-time overload.
2.3.2 General design features
The above design criteria are met by a delta/star transformer having an open-circuit voltage ratio of 23.5/ 11.8 kV, equivalent to 23.5/11 kV at full-load 0.8 power factor, with off-circuit taps on the HV winding of +7.5 07o in six steps of 2.5°70. For the reasons explained in Section 1.5.6 of this chapter, these are varied nowadays by means of links under the oil rather than using an off-circuit switch which was the previous practice. The changeover of unit and station supplies normally only requires that these transformers be paralleled for a few seconds. This is long enough for the operator to be sure that one circuit-breaker has closed before the other is opened. During this time, however, a circulating current can flow which is dependent on the combined phase shift through the unit, generator and station transformers, plus any phase shift through interbus transformers, if generator and station transformers are not connected to the same section of the grid system. This can result in the unit transformer seeing a current equivalent to up to 21/2 full-load. Should the operator take longer than expected to carry out this switching, the unit transformer windings will rapidly overheat. Such a delay is regarded as a fault occurrence, which will only take place fairly infrequently. It is considered that parallel operation for a time of two minutes is more likely to occur than a short-circuit of the transformer and so the limiting
aookv SUBSTATION
NORMAL POWER FLOW
• a•
•
NORMAL POWER FLOW
400 132kV fNTERBUS TRANSFORMER
•
400235 kV GENERATOR TRANSFORMER
NORMAL POWER FLOW
NORMAL POWER FLOW
11 kV UNIT BOARD
••
CIRCULATING CURRENT
4
FIG. 3.62
132 11kV STATION TRANSFORMER
•
•
PHASE DIFFERENCE BETWEEN THESE BOARDS
262
••
11kV STATION BOARD
NORMALLY OPEN 1 lcV CIRCurT BREAKER
Paralleling of station and unit transformers
Special design features temperature is set lower than the temperature per° mitted on short-circuit. The latter is set at 250 C by BS171 and so the CEGB has specified that a figure of I80°C should not be exceeded after a period of two
brief series of works tests. It is therefore necessary to accept change gradually, to ensure that quality assurance systems are maintained and that all the testing that is practicable is carried out.
minutes parallel opet al ion.
2.4.1 General design features
2.4 Auxiliary transformers The auxiliary transformers in a power station are by far the most numerous and varied. They range in size from 12.5 MVA 11/3.3 kV to possibly as small as 315 kVA. They can be oil-filled to BSI48[121, or dry tspe, or occasionally filled with some synthetic liquid (although it should be noted that filling with polychlorobiphenyls — PCBs --- once the most common amongst the fire-retardent fluids, has been dropped by the CEGB since the early 1970s). Auxiliary transformers are very likely to be made in a different factory from the larger transformers. Being smaller and lighter they do not require the same specialised handling and lifting equipment as the larger transformers. Vacuum i mpregnation and vapour-phase drying (see Section 1.7.3 of this chapter) equipment is not requited. At the very small end of the range, manufacturing methods are closer to those used in mass production industries. There are many more manufacturers who make small transformers than those at the larger end of the scale. The industry is very competitive, margins are small and turnround times are rapid. The result is that there is a constant tendency for manufacturers to look for cheaper and simpler ways of making the product and a 2 MVA transformer built in 1985 would appear very different from one made twenty years earlier. To date, changes tend to have been restricted to methods of cutting and building cores, simplification of core frames and simplification of the arrangement and method of forming internal leads, for example, by the use of round rather than flat copper bar for HV connections. Round bar, being stiffer, usually requires fewer supporting cleats and since it can be bent with equal ease in all planes can usually be taken from point to point in a single formed . length, whereas flat bar might require several specially formed bends and joints in order to follow a complex route. These changes have generally found acceptance with the CEGB. There have been some new materials and processes, notably in the use of crimping rather than sweating or brazing for the making of joints. This has the advantage that it avoids the need to bring a blow torch into close proximity of windings with its associated risk of fire or, at the very least, overheating of insulation. Crimped joints are also made very much more quickly than brazed or sweated joints, leading to Cost savings. All this is quite acceptable provided that there is no resulting loss of reliability or life expectancy. In Section 1.7 of this chapter. the point has been made that these two factors are difficult to assess from a
Auxiliary transformers of 11/3.3 kV are normally either 12.5, 10 or 8 MVA. These transformers are oil-filled, which means that they are located outdoors and provided with waterspray fire protection unless positioned remote from main buildings. Connections at II and 3.3 kV are in cable which means that cable boxes must be provided for HV and LV terminations. Cooling is invariably by natural circulation of the oil, with natural air-cooling of the tank-mounted radiators. A conservator is provided to allow expansion space for the oil and in order to allow a Buchholz relay to be fitted. The air space within the conservator is vented to atmosphere via a silica-gel breather. A pressure relief device is mounted on the tank cover. Transformers for 3.3/0.415 kV normally have ratings of 2, 1.6 or 1 MVA in order to match the standard current ratings of 415 V switchgear, although smaller ratings, for example, 800 kVA or 500 kVA, might be used occasionally. For these ratings a number of design options exist and, in fact, it is becoming increasingly common practice to employ an alternative to class A, mineral oil-filled insulation. One reason for this is that in large modern power stations it is difficult to locate oil-filled transformers outdoors whilst keeping them close enough to plant to obtain acceptable cable volt drops.
2.4.2 Auxiliary transformer insulation systems In the late 1970s and early 1980s several new dielectric/ insulation systems for small auxiliary transformers were introduced. This largely arose as a result of the environmental status of polychlorinated biphenyls (PCBs). For many years these were the only dielectrics in general use where it was necessary to eliminate the fire hazard associated with oil-filled transformers, but in the early 1970s it was recognised that these nonbiodegradable fluids posed serious environmental hazards when they were accidentally released into the environment. Their use by the CEGB in transformers was therefore discontinued. Because of the number of options which are available for auxiliary transformers in this range, it is worth examining them in some detail. The following insulation systems will be considered: • B5148 oil with class A insulation for comparison. • Dry-type air-cooled with class C insulation. • Encapsulated cast-resin. • Synthetic liquid with class A insulation. 263
Transformers Reasons for considering alternative dielectrics BS148 oil has had widespread use for auxiliary transformers in power stations for so long and has proved so reliable that it is reasonable at the outset to question hy alternative dielectrics should be considered. The disadvantages of oil-filled auxiliary transformers can be summarised as follows: • Oil is considered a lire hazard so these transformers must be located outdoors. • This means relatively lengthy cable runs for both HV and LV cables. LV cables in particular are bulky and expensive. • The need to locate transformers outdoors creates layout difficulties, since it becomes exceedingly difficult to position these close to the load. At Drax, for example. long 415 V cable runs for precipitator electrical supplies led to the need for on-load tapchangers on transformers providing these supplies, with all its attendant extra costs and complexity, • Even when located outdoors, these transformers must be provided with fire protection in all situations, except where they are located remote from main buildings. • The need to guard against pollution of drains means that transformer compounds must be provided with special drainage facilities, with interceptor tanks large enough to cater for major oil spillage coupled with the operation of waterspray fire protection. The following are the alternatives: Dry-type air-cooled class C insulated (AN) These have been considered by the CEGB to be the main alternatives to oil-filled transformers since the early 1960s. Advantages of air-cooled transformers All the disadvantages of oil-filled transformers listed previously are eliminated. • They can be regarded as almost totally fireproof. '[here is very little combustible material associated with their construction and those materials which are present are used in such small quantities and are of such low flammability as to constitute negligible risk. • There are no liquids involved whatsoever, therefore there are no risks of spillages, no need for bunding or protection of other equipment. • There are no toxicity problems. • The transformer can be made integral with 415 volt SNk i t chgear, therefore LV cabling can be eliminated. 264
Chapter 3 Figure 3.63 shows a typical 415 V switchboard with an integral 3.3/0.415 kV transformer. Disadvantages of air-cooled transformers • The transformer and its enclosure cost about 1.8 ti mes that of an oil-filled transformer of equivalent rating • Past designs of air-cooled transformers tended to have poorer reliability than oil-filled. • The weight of the transformer means that switchroom floor loadings must be designed to take this into account. • Provision must be made for dissipation of transformer losses from switchrooms. • The transformer must be provided with a reasonably clean, dry, environment, although this need be no better than the environment normally provided for switchgear and contactor gear. Care is necessary on re-energising after any period out of service to ensure that the windings are moisture free. In weighing the disadvantages of AN transformers against the benefits, those which figure most prominently are cost and reliability. The extra cost can be very much offset by the savings on LV cabling, transformer compound provision and drainage, and the elimination of a fire protection requirement. It is difficult to build up an accurate balance sheet since a number of factors are very difficult to cost. For example, space saving in cable tunnels and losses in LV cables on the credit side versus the provision of extra space (and possibly extra structural strength) in switchrooms and extra ventilation on the debit side. On balance, the extra cost of the transformer is almost totally offset by these factors. It was certainly the CEGB experience that in the early days of their use, AN transformers had poorer reliability than their oil-filled counterparts. In fact, since small oil-filled auxiliary transformers are virtually never known to fail in a power station situation (as distinct from Area Board experience, where such transformers are used in electrically-exposed situations), their reliability cannot be bettered. However, the more rigorous works testing and inspection procedures for AN transformers instituted by the CEGB, coupled with the appearance of polyamide-paper-based insulation in the late 1960s, has improved their reliability considerably. This conclusion is based on a fairly small sample of AN transformers in service, compared with the numbers of oil-filled transformers in operation. In terms of 'large modern' stations, at the time of writing (1988) this means Wylfa, Dungeness, Heysham / and Littlebrook D, and there were problems at the first two stations during their early life.
Special design features
FIG. 3.63 415 V switchboard with an integral 3.3/0.415 kV transformer
Cast-resin insulated
Cast-resin insulation made its appearance in power transformers in significant quantities in the 1970s. Before that it had been used in instrument transformers for a number of years. Its use on the continent of Europe has been very much more widespread than in the UK and the expansion of the market in the UK coincided with moves by environmentalists to han PCBs. The CEGB has little experience of cast resin for power transformers, so in assessing the advantages and disadvantages no first-hand experience is available except in discussing those properties which cast-resin power transformers have in common with instrument transformers, particularly VTs. Advantages of cast-resin insulation As with
AN transformers, the disadvantages of oil-filled transformers are eliminated. • The insulation system is virtually indestructable and dielectric failure due to neglect of environmental conditions can be disregarded.
• As with AN transformers there are no liquids involved. Cast-resin transformers designed for installation in a 415 V switchboard are illustrated in Fig 3.64. Disadvantages of cast-resin insulation
• Because of the high cost of moulds, manufacturers are usually only able to offer a limited range of ratings and impedances and insulation levels. These generally will not coincide with the CEGB specified requirements. • Cost is greater than AN (say, 10-20°o more in 1987) with little identifiable benefit. • Due to the problem of differential expansion between copper and resin, the transformer has virtually no overload capability, even for a short time. Overload protection is required. • There are also the weight and heat-dissipation problems, as discussed for AN transformers. 265
,
44
.6.1%
FR:. 3.64
Cast-resin iransfornicrs for installation in 415 V switchgear (GE(' Alsthom) (sec also colour photograph between pp 496 and 497t
SJOULIOJSUe.11
Vi.ippyr
Special design features There have also been suggestions that, although a castresin transformer is unlikely to initiate a fire, should a fire occur which involved the transformer, the resin %vitt then burn producing heat and smoke. However, recent testing carried out by the CEGB and by the manufacturers of cast-resin transformers has proved that this fear is unfounded. The CEGB has experience in the use of two types of cast-resin transformers: • For use as 23,5 kV generator voltage transformers. • For use as generator neutral earthing transformers (see Section 2.5 of this chapter). In both of these applications the benefits are sufficiently worthwhile to outweigh some of the disad\. antaues listed. One listed disadvantage — that of inability to purchase a transformer which meets the CEGB specification — does not apply in that there are specialist designs available which fully meet CEGB requirements. The problem of lack of overload capability is avoided \ very conservatively rating the transformers in question. This is an approach which could not normally be justified but which is permissible where the benefits of resin are paramount. Faults which have resulted in merloading cast-resin voltage transformers have, however,produced spectacular and catastrophic failures. The excellent insulation properties of cast-resin are demonstrated in the damp heat test which the CEGB applies to cast-resin VTs. In this test, 23.5 kV voltage transformers, which are dripping with surface condensation, are required to withstand 1.2 x rated voltage for one hour, followed by a final five minutes at 1.9 x rated voltage. It is this ability to survive severe adverse conditions which justifies the use of cast-resin v, here the service location or operating regime gives rise to such exacting conditions. It should also be noted that the use of aluminium, usually in the form of foil windings, improves the o ■ erload capability of cast-resin transformers, since he thermal expansion of aluminium differs from that of the resin to a lesser degree than does that of copper. \ !though the use of both copper and aluminium foil indings is tending to become widespread in small Area hoard distribution transformers, this remains the only significant application for power station transformers.
Synthetic liquid filled Since the banning of PCBs, many other dielectric fluids have appeared on the market. None is as good as PCBs in all respects but they are acceptable environmentally. In the USA, there were very large numbers of PCB-filled transformers and there have also been the strongest pressures from the environmentalists to eliminate them. This has given the alternatives a commercial boost.
At the present time, the full list of synthetic dielectric fluids is too lengthy for coverage in a volume such as this. For full details of all such fluids available the reader is referred to specific works on dielectric fluids [13], however, the following represents the salient features of the better known fluids in the UK in 1987: This was probably the first replacement for PCB to appear in any quantity. Manufactured and marketed by the Dow Corning Corporation, it has been used in fairly large quantities both as a retrofill fluid, replacing the PCB in existing transformers, and in new transformers. Its thermal properties are not as good as those of PCB or BS148 oil so that transformers designed for PCB and filled with silicone fluid have to be slightly derated. There have been no significant adverse reports to date.
Silicone fluid
Midel 7131 was developed by Micanite and Insulators, who are currently part of the UK GEC group. It has been widely used both in the USA and the UK, and to date there have been no adverse reports. Midel does not require the derating demanded by silicone fluid when used as a retrofill fluid and its only known disadvantage at the present time is its high cost.
Midel 7131
Formel NF Forme' NF has been jointly developed by ISC Chemicals of Avonmouth and the Electricity Council. It is probably the only truly non-flammable dielectric fluid which is currently available. For the Electricity Council to come to the decision to develop this fluid is perhaps an indication of shortcomings in the other fluids available. It has not been used in power station applications since, as explained above, current policy is to dispense with liquid dielectrics for transformers within buildings. The fluid is a mixture of halocarbons of the type which have found widespread use in fire-retardent cable insulation. It is likely that future policy will be to discontinue the use of such halocarbon materials because of the considerable quantities of damaging smoke and fumes produced from them when engulfed in a fire. It should be noted that, unlike most other dielectric fluids available, formel NF is not suitable for use as a retrofilling fluid. One further fluid worthy of mention is RTEmp. This is used fairly widely in USA and is cheaper than either silicone or Midel. Its only known disadvantage is its high viscosity at low temperatures.
RTEmp
2.4.3 Design features of dry-type transformers For the reasons identified in the previous section, aircooled dry-type transformers having class C insulation are now the most common means of providing 415 V supplies. Normally these take their supply from 3.3 kV, although occasionally the primary voltage is 11 kV. 267
Transformers
Chapter 3
The object in eliminating the dielectric fluid is to enable the transformers to be located close to the load and the standard arrangement is to incorporate them into 415 V switchboards. Such an arrangement is illustrated in Fig 3.63 and is shown diagrammatically in Fig. 3.65. 415 V busbars are arranged to connect directly to the terminals of the incoming 415 V circuitbreaker of the switchboard. Since the majority of such 415 V boards have two transformer incomers either side of a bus-section switch (as shown in Fig 3.66), it is necessary for the transformer section to house the length of through busbars. The usual practice is for the transformer manufacturer to supply the transformer enclosure together with this length of through busbar. The busbar must be suitably segregated from the interior of the transformer cubicle, since it will probably be alive at the time that the transformer itself has been isolated to allow access. The through busbar must be braced against short-circuit forces to the same standard as the busbars in the remainder of the switchboard and it must be capable of carrying
3kv SUPPLY CABLE
TRANSFORMER CUBICLE
415V CIRCUIT BREAKER
415V OUTGOING CIRCUITS
1. it,. 3.65 415 switchboard with integral 3.3/0.415 kV transformer
TRANSFORMER 'A'
•
415V CIRCUIT BREAKER
TRANSFORMER 'B'
BUS-SECTION THROUGH BUS - BAR
4)5v CIRCUIT BREAKER 'B'
FIG. 3.66 415 switchboard with two 3.3/0.415 kV
transformers 268
full-load current without exceeding the specified temperature rise in an ambient -generated by the normal transformer losses dissipated within its enclosure. This requirement is particularly onerous since the transformer is permitted a temperature rise of 150 ° C which is somewhat higher than that allowed for busbars within switchgear. The FIV connections to indoor dry-type transformers are invariably via cables. With modern plastic insulated cables, it would be possible to bring these into the transformer enclosure and terminate them directly Onto the ends of the HV winding and, indeed, this practice is common in some European countries. However, the arrangement has the disadvantage that during station construction the cabling contractor must have access to the interior of the transformer enclosure, with the attendant risk that the unprotected insulation of the transformer windings might be damaged. This is not considered a worthwhile risk to take for the comparatively modest benefit of eliminating a cable box and so it is standard CEGB practice to terminate cables in a conventional box mounted on the exterior of the enclosure. With cast-resin insulated windings there is much less risk of damage and elimination of the HV cable box is acceptable. The size and rigidity of the enclosure in relation to that of the transformer usually requires that it be delivered to site separately from the transformer. It is thus necessary to provide it with access doors large enough to enable the transformer to be taken in and out; this operation is simplified by mounting the transformer itself on rollers. The doors also provide access to the interior of the enclosure for the occasional cleaning necessary during service. Safety for access when installed is ensured by the use of a key interlock arranged such that the enclosure doors can only be opened when the transformer HV circuit-breaker is in the circuit-earthed position. It is normal CEGB practice to apply a local temporary earth at the point of supply to a dry-type transformer whenever access is gained to the interior of the transformer cubicle. A type of earth connection which is clamped at one end onto a 15 mm diameter bar by means of a remote handling pole is used. The `earthy' end is connected via a length of flexible cable and an earth-end clamp to the switchgear earth bar which must be brought to a suitably accessible point external to the transformer enclosure. With the lineend clamped to the HV connection inside the transformer enclosure and the earth-end clamped outside the enclosure, this ensures that the doors cannot be closed and the HV circuit-breaker released from the `circuit earth' position until the temporary earth has been removed. For many years, it was considered impracticable to provide a dry-type transformer with any winding temperature indication since, not being immersed in a medium such as transformer oil to which any temperature rise could be referred, it was difficult to obtain
Special design features a reference basis. The best that could be achieved was to place a sensor in a position which it was hoped would xpoSe it to the hottest cooling air. Thermal image e devices of the type used in oil-filled transformers ha' c recently been developed to provide indications of reasonable accuracy. As with the oil-filled equialent, these employ a heater coil having a temperature rise equal to that of the calculated hot-spot temperature. . This surrouna : a mercury-in-steel thermometer bulb hich is placed in the hottest outlet air and thus aims :o reflect the true hot-spot temperature. The main problem with such devices is that they require that the designer should have an accurate knowledge of what the hot-spot temperature will be, which may not necessarily be so.
THYRISTOR RECTIFIERS
POSITIVE
NEGATIVE
2.4.4 Special transformers
Because of the requirement for a neutral connection on 415 V systems, both for earthing and to enable 240 V single-phase loads to be supplied, transformers stepping down to this voltage level are almost invariabb. star connected on the LV side, with a delta connection on the primary (see Section 1.1.1 of this chapter). The exception is when the low voltage side supplies significant amount of rectifier load, as in certain electrolytic gas production plants. For very large rectifier loads, the magnitude of harmonic currents drawn from the supply can result in considerable distortion of the supply voltage waveform, particularly if the loads from a number of parallel rectifiers are all drawing harmonics in phase with each other. The problem is unlikely to occur for smaller loads such as battery chargers or for battery-backed inverter systems for computer and instrumentation supplies. Many rectifier transformers employ a 'six-phase' delta/star/star connection arrangement as shown in Fa2 3.67 (a) and this of itself helps to reduce harmonic distortion by elimination of even harmonics. However an improved arrangement can be obtained by doubling the number of supply transformers and providing half or these with an interconnected star (Fig 3.67 (b)). 1 . his aims to displace half the rectifier load, and its acsociated harmonic currents, by 30 so as to reduce the resultant magnitude of any given harmonic current drawn from the supply. Although elimination of harmonics generated by thyristor loads has not yet become a major problem for power station auxiliary systems, it is an increasing one due to the growth in the use of thyristor drives and there is considerable literature on the subject, for example, Electricity Council Engineering Recommendation 05/3 [14] and in the technical press (15]. The subject of avoidance of harmonic distortion ol power supplies caused by converter equipment is Important. It is dealt with in detail in Electricity Council -
Report ACE 15 [16]. In most other respects rectifier transformers are si milar to any other small auxiliary transformer. The
INTERPHASE CHOKE
(a) Six-phase
rectifier transformer
(b) 12 pulse rectifier using star/star and Starinterstar transformers and full wave bridge rectifier rectifier transformer and rectifier transformer bank of delta/star and interstaristar transformers
Eio. 3.67 'Six phase'
harmonic currents referred to above can produce additional heating. Also, with certain connection arrangements, polyphase transformers can be subjected to a DC component of current in their secondary windings so that temperature rise tests should be carried out, if possible, in conjunction with the associated rectifier. These transformers are almost invariably dry-type, class C, so that they can be installed indoors in a cubicle adjacent to the rectifier. Another special requirement of some small auxiliary transformers is that of low magnetising inrush current. The existence of a large magnetising inrush current is normally regarded as an inevitable feature of a power transformer. The phenomenon is dealt with in some detail in many text books [2]. For the largest transformers, it must be allowed for when selecting protection settings; for smaller transformers, supply fuses need to be suitably rated to avoid spurious failure. Normally this represents no more than a minor 269
Transformers
Chapter 3
inconvenience. However, a recent application has led to the specification of a specially low magnetising inrush current for certain small instrument supplies transformers as used in uninterruptible power (UPS) supplies systems. Figure 3.68 shows a UPS system which can be fed either from the battery-backed inverter, or from the mains should this fail. Fuses Fl, F2 must be set low in order to protect the inverter from damage in the event of load-side faults. However, these fuses are subjected to the magnetising current of the transformers (Ti and T2) on operation of the changeover switch (S) that provides the continuity of supply from the mains in the event of failure of the inverter. For a system employing an 8 kVA transformer, a fuse rating of 25 A is required to provide the necessary protection for the inverter. The peak magnetising inrush current at 415 V for a transformer of this size would normally be over 200 A. To avoid operation of the fuse it is necessary to ensure that the first peak magnetising current does not exceed about 140 A. The other limiting factor which makes the transformer specification somewhat exacting is that, because of the nature of the loads fed from such a UPS system, the transformer impedance must not exceed about 2 07o to meet regulation requirements. Such transformers can be designed, albeit with difficulty. Achievement of the requirement is assisted by operation at low flux
415V SUPPLY
OATTERY CHARGER
IN BATTERY
STA TIC SWITCH
415.110V TRANSFORMERS
110V UPS DISTRIBUTION BOARDS
FIG. 3.68 UPS system with inverter or mains-fed transformer
270
density (about 1 T) and by the use of a primary winding which has a large air cross-section in relation to the iron cross-section of the core. Hence this winding is usually made the outer winding of a double-concentric arrangement. The magnitude of the first peak inrush current is dependent on the remanent flux within the core at the instant of energisation and the precise point on the applied voltage wave at which this takes place. The inrush is greatest when switch-on is at voltage zero with the remanent flux within the core at its maximum value and in the opposite sense to that appropriate to the applied voltage. The chances of this occurring for any single random switching is low, hence, in order to carry out an effective proving test it is necessary to use a point-on-wave switching device and to ensure that the core is suitably magnetised.
2.4.5 Foil windings During the latter part of the 1960s, the price of copper rose steeply and threatened to rise still further, so a number of manufacturers began to experiment with aluminium for transformer windings, mainly in small distribution transformers up to about 500 kVA: the majority of these had foil windings. In addition to avoiding the need for welded joints in wire, this arrangement has the attraction for the manufacturer that windings can be machine wound and, once the machine has been set up, can be produced very rapidly. There is no record of these transformers so far being used in power station applications. However, the subject is worth mentioning in a section dealing with power station auxiliary transformers since their introduction remains a possibility, particularly in conjunction with a cast-resin insulation system, as noted in Section 2.4.2 of this chapter. Many users of early foil-wound transformers experienced problems in service arising from the connection between the foils and the risers to the transformer terminals. These frequently involved H V windings where the foil is exceedingly flimsy and the situation is further complicated if HV taps are specified. The interfoil insulation for foil-wound transformers has been almost exclusively melamine sheet. This is exceedingly thin (less than 0.1 mm) and can be easily punctured by the inclusion of minute particles of dirt or grit, causing failure in service. This can be avoided by manufacturing under clean conditions. There is an additional problem that if the edge of the foil itself is slightly burred or ragged, this too can cause puncture of the melamine. There are also problems of handling the melamine due to the very low coefficient of fricLion between this and aluminium foil. Coils before impregnating require very careful handling and can be very easily 'telescoped out' at this stage. To overcome this there have been attempts to bond the melamine to thin paper to increase the coefficient of friction.
Special design features Another problem with foil-wound HV windings, particularly when delta connected, is that full line, voltage appears across the end of the winding rather than b e ing distributed along its length. For this reason and he problems associated with the use of very thin foil t previously mentioned, some manufacturers have used foil-wound LV windings in conjunction with conventional wire-wound HV windings. Transformers with aluminium-foil windings have , been found not o be significantly cheaper than those using copper. They have higher losses and at the end of their useful life the aluminium, unlike copper, has zero scrap value. A recent development has been the use of copper foil rather than aluminium. This should largely reduce the problem of making connections to the foil, but the benefit of low material cost is sacrificed. It would seem that the attraction is simply that of reduced manufacturing cost by simplification and of something approaching mass production being applied to the
restricted fault current would flow. It is thus necessary to locate the neutral earthing transformer adjacent to the generator neutral, and an oil-filled transformer cannot be used because of fire hazard. A transformer of high reliability with low fire risk is needed. Polychlorinatedbiphenyl-filled transformers were initially used for this purpose but these are now excluded on environmental grounds. In other low fire-risk applications, the CEGB uses class C insulated dry-type transformers, but these are most prone to failure if suddenly energised after a long period in a de-energised condition, which is just the condition applied to a generator neutral earthing transformer in the event of a system earth fault. In 1976, the CEGB decided that this was an ideal application for a cast-resin transformer and therefore drew up a specification for such a transformer. After extensive testing of a prototype, the system was adopted for the earthing of the Dinorwig generators and has become the standard arrangement for subsequent stations.
winding process. 2.5.2 Generator neutral earthing transformers
2.5 Neutral earthing 2.5.1 Generator earthing transformers — basic principles The practice of earthing the neutral of large generators via a high resistance was developed in the 1950s with the object of restricting stator earth fault current to a low value and thereby limiting the damage caused by the fault. The aim with the system currently in use is to limit the current for an earth fault on the windings of a 23.5 kV generator to between 10 and 15 A. This requires a resistance of about 1400 2. If connected directly into the generator neutral a resistor of this value for such a low rated current would tend to be rather flimsy as well as expensive. The solution is to use a resistor of low ohmic value to load the secondary of a transformer whose primary is connected in series with the generator neutral earth connection. When the system was first devised the intention was o use a standard low cost single-phase distribution transformer. Since that time, generator voltages and ratings have increased considerably and the need for hiv.h security means it is no longer possible to use such a transformer. The following section describes the special characteristics of generator neutral earthing transformers v.hich have been developed at the present time. For a detailed description of the protection aspects the reader is referred to Chapter 11 of this volume. The generator neutral connection to the primary of an earthing transformer, or any other high resistance neutral earthing device, must be kept as short as possible since this connection is unprotected. An earth tault on this connection would go undetected until a second fault occurred on the system and then an un-
— general design features The detailed requirements for generator neutral earthing transformers are set out in the CEGB Generation Design Memorandum (Plant) No 80. For the neutral of a 23.5 kV, 660 MW generator a voltage ratio of 33/0.5 kV is selected. The primary voltage insulation level of 33 kV corresponds to that used for the generator busbars (see Chapter 4 of this volume) thus maintaining the high security against earth faults. It also ensures an adequate margin of operating voltage over that which could appear on the generator neutral under AVR field-forcing conditions (assumed to be 1.4 times normal volts) with an earth fault on one of the generator line terminals. With this field-forcing condition, the nominal 10 A earth fault current becomes 14 A, hence the transformer should have a rating of 14 x 33 000 = 462 kVA. However this only needs a five-minute rating, since an earth fault of this magnitude would lead to instantaneous operation of the generator protection. The required continuously rated current is that which is just too low to operate the protection, plus an allowance for third-harmonic currents which may flow continuously in the generator neutral. The aim is to protect as much of the generator windings as possible and so the minimum current for operation is made as low as possible. This is taken to be 53/4 of the nominal setting of 10 A, i.e., 0.5 A. Tests on 660 MW turbine-generators suggest that the level of third-harmonic current is about I A. The transformer continuous rating is thus (0.5 + 1) x 33 000 = 49.5 kVA. In practice a typical transformer of this size has a continuous rating of 0.2-0.25 of the five-minute rating, hence the continuous rating is accommodated naturally.
271
Transformers 2.5.3 Practical arrangement
The generator neutral earthing transformer should be located as close as possible to the generator neutral. For modern 500 and 660 MW machines the neutral star-point is formed in aluminium busbar located underneath the neutral end of the generator, usually at the turbine hall basement level. It is housed in a sheet-aluminium enclosure which provides protection tor personnel from the operating voltage as well as electromagnetic protection to the surrounding plant from the large flux generated by the high machine phase currents. (This is described in greater detail in Chapter 4.) The neutral earthing transformer in its enclosure, which usually also houses the resistor, is arranged to abut the neutral enclosure in such a way as to enable a short 'jumper connection' to be made from a palm on the generator star-bar to one on the transformer line-end terminal via suitably located openings in the neutral enclosure and transformer enclosure. On generators 4, 5 and 6 at Drax power station, the transformer was made with long flexible connections to the secondary loading resistor and arranged so that it can be 'racked forward' towards the 2enerator star-bar once transformer and resistor have been placed adjacent the neutral enclosure, thus enabling a very short connection indeed to be made between the star-bar and the transformer. A generator neutral bar and its earthing connection is shown in Fig 3.69. 2.5.4 Loading resistor
value of apparent resistance required in the generator neutral is V/Irs.s3 0, where V is the generator li ne voltage and Jr the specified stator fault current. When referred to the low voltage side of the transformer, this becomes V/v 2 1 0./3 0 where v is the turns ratio of the transformer. Inserting the values already given for a 660 MW 23.5 kV generator gives a resistance value of about 0.3 0. Strictly speaking this is the total secondary resistance including that of the transformer, but since a transformer of the rating quoted above has an equivalent resistance of >0.01 ohms, this can be neglected within the accuracy required. It is also necessary that the X/R ratio for a transformer/resistor combination does not exceed 2, in order to ensure that the power factor of arcing ground faults is as high as possible and that re-striking transients are kept as low as possible. In fact, a practical transformer meeting the other parameters specified above can fairly easily be designed to have a reactance of about 4 07o based on the rating of 462 kVA for the transformer of a 23.5 kV, 660 MW unit which equates to 0.0025 0. This would give an X value of about 0.08, assuming the resistor to be non-inductive, and would allow the resistor to have considerable inductance before causing any embarrassment. The CEGB Design Memorandum states that the The
272
Chapter 3 resistor should be non-inductive but this is simply erring on the side of caution and ensuring that there is no likelihood of the maximum X/R value being exceeded inadvertently. Generally, a non-inductive resistor would be flimsier than one which has some inductance because of the construction needed to give this characteristic. Economics might therefore dictate that the resistor is allowed to have some inductance: if so, it is important to know its magnitude and to ensure that the permissible X/R ratio is not exceeded. Typical forms of construction of both inductive and non-inductive resistor elements are shown in Fig 3.70. The resistor rating can be calculated on the basis of I 2 R, where I equals 924 A, equivalent to a primary current of 14 A, and R equals 0.3 ohms. This works out to about 260 kVA, which is usually rounded up to 300 kVA and is the required five-minute rating. This is not equal to the five-minute rating of the transformer, since the latter has been based on a notional voltage of 33 kV rather than the actual applied voltage of (1.4 x 23.5)/V3 = 19 kV. The resistor must also have a continuous rating. For the example quoted, this is 1.5 A in the transformer primary or 99 A in the secondary, giving about 3 kVA for a 0.3 0 resistor. As with the transformer, a resistor which can meet the five-minute rating easily satisfies the continuous rating. Other parameters of the loading resistor are conventional for metal resistors of this type. It must be
housed in a sheet steel enclosure which provides protection against personnel access and accidental contact. This can be a common enclosure with the transformer, as indicated in Fig 3.69. However, if a common enclosure is used, there should be a metal barrier between resistor and transformer so that the transformer is protected from any directly radiated heat from the resistor. The external temperature rise of the enclosure after operation must not exceed about 80 ° C to avoid possible injury to anyone coming into contact with it. 2.5.5 Generator busbar system earthing
In an installation having a generator circuit-breaker, a second earth must be provided for the 23.5 kV system, otherwise the system on the transformer side of the generator circuit-breaker would be unearthed when the generator circuit-breaker was open (see Fig 3.71). This earth must have an impedance of a similar order to that of the generator neutral earth; if not, the benefits from high resistance earthing of the generator neutral would be lost. Hence, a second transformerconnected resistor is needed. However, first it is required to provide a neutral for connection to earth. This is obtained using an interconnected-star arrangement (see Section 1.1.3 of this chapter) for connection to the 23.5 kV system. The neutral point thus produced is then connected to the primary of the neutral earthing transformer. The most convenient location for connection to the 23.5 kV system is via a tee-off from
Special design features
Flo. 3.69 Arrangement of Dinomig generator neutral earthing transformer (Balfour-Beatty Power Construction Ltd)
273
Transformers
Chapter 3
( h)
3.70 Typical forms of construction of metallic resistors (a) Neutral earthing resistor having low inductive elements (GEC Industrial Controls) (b} Neutral earthing resistor having non-inductive elements (Air Industrial Developments Ltd) 274
Special design features
GENERATOR TRANSFORMER
GENERATOR CIRCUIT-BREAKER
MAIN GENErIATOR
GENERATOR NEUTRAL EARTHING TRANSFORMER
_L
UNIT TRANSFORMER
"z"-BUS-BAR SYSTEM EARTHING MODULE
FTC, 3.71 Arrangement of 23.5 kV system busbars for a unit having a generator circuit-breaker
the main generator connections adjacent to the unit transformer, so that the interstar 'transformer' can be located outdoors alongside the generator and unit transformers and can thus be oil-filled. The 33/0.5 kV neutral earthing transformer can be installed in the same tank as the interstar transformer to provide a 23.5 kV system earthing 'module' shown diagrammatically in Fig 3.72. The rating of the 33/0.5 kV portion of this module must be the same as that used for connection to the generator neutral. The interstar windings must be capable of carrying the unrestricted current that would flow with an earth fault on the 23.5 kV system, with the generator circuit-breaker open and the neutral earthing transformer shorted out (see Chapter 11). For
PPOTECTION
CT
INTERCONNECTED STAR 'TRANSFORMER'
FIG. 3.72 Arrangement of 23.5 kV system earthing module
the system parameters appropriate to a 660 MW unit, this has been calculated as 550 A. It is assumed to persist for a time of 3 s which allows for the operation of back-up protection to clear the fault. 2.5.6 Harmonic suppressors
Sometimes an auxiliary system is required to operate for a long period with two earths connected to it. For example, a diesel generator providing emergency supplies when all other AC supplies have been lost must have a neutral earth connection when running in this condition. However, the same generator is required to run in parallel with the normal auxiliary system when normal supplies are being restored and also for test running purposes. In this situation its neutral earth connection will be in parallel with the auxiliary system earth connection. Although the return to normal supplies operation might involve no more than a brief period of paralleling, the test running condition might well be for a much longer period. A system with two earth connections provides a path for circulation of third harmonic currents (see also Section 2.2.2 of this chapter) and these can produce unacceptable additional heating in generators, transformers and, in particular, earthing resistors. Where earthing resistors are of the electrolyte-filled variety, probably short time rated, this third-harmonic heating can be a severe embarrassment. One possible solution is to utilise a switched neutral connection interlocked to ensure that only one connection is made at any one time. However, the control of this can be complicated and a simpler solution is to install a third-harmonic suppressor. This is an iron-cored inductor which is connected in series with one of the neutral/earth connections, usually the one which is not normally connected to the auxiliary system. Its design flux density is such that it is totally saturated at 50 Hz, thus having a low impedance at normal supply frequency, whereas at 150 Hz it operates below the knee point and, being unsatu275
Transformers rated, has a high impedance, effectively equal to the magnetising reactance. Practical values are less than 2 2 for an 11 kV device with an applied voltage equal to 10% of generator phase voltage at 50 Hz, and greater than 150 Si with this same voltage applied at 150 Hz. It must be rated for the continuous third-harmonic current produced by the expected level of third-harmonic voltage when applied to the combined impedance of the device and any neutral earthing resistor. In addition, it must be capable of carrying the fault current resulting from an earth fault on the associated system. For an 11 kV system, as provided for station or unit supplies associated with a 660 MW generator, this will be either 1000 A for 30 s, if limited by the system neutral earthing resistor, or 10 000 A for 3 s should this earthing resistor have been short-circuited. The above currents determine the thermal rating of the harmonic suppressor. Should a system earth fault occur, coincident with a short-circuit of the neutral earthing resistor, the first-loop peak of the fault current will be limited only by the fully-saturated impedance of the harmonic suppressor and any impedance of the supply. The latter, being designed to the limits of the fault capability of the auxiliary switchgear, for example, 750 MVA at 11 kV, will be very low indeed. The fully-saturated impedance of the harmonic suppressor is that measured with an air-core alone and, for an 11 kV device designed to meet the requirements listed above, can be as low as 0.15 it resulting in a first-loop peak fault current of the order of 50 000 A. Such a fault current imposes a very high mechanical load on the suppressor and it is normal practice to prove the withstand capability by carrying out a type test on any new design at this level. Because the suppressor has a high impedance to high frequencies, as represented by any voltage transients which might occur on the system, it is normal practice to connect a surge diverter across its terminals to provide a safe shunt path for these. Figure 3.73 shows the typical arrangement of a harmonic suppressor as installed in the neutral earth connection of an 11 kV gas-turbine generator associated with a 660 MW unit.
Chapter 3
CONSERVATOR
SURGE DIVERTER iikv BUSHING "
CABLE BOX
HARMONIC SUPPRESSOR
Th
ALTERNATIVE POSITION FOR CABLE BOX
CONCRETE PLINTH
BUSHING RESISTER SIDE
GENERATOR SIDE CABLE BOX
Fic. 3.73 Arrangement of 11 kV harmonic suppressor
3.3 kV, the need for such current limiting reactors is rare. Their use on power station auxiliary systems is, therefore, the exception rather than the rule. There are four basic types of current limiting reactor. These are: • Cast-in-concrete air-cored. • Oil-immersed gapped iron-cored.
2.6 Series reactors 2.6.1 General design features
Series reactors are sometimes referred to as current li miting reactors and, as the name suggests, are used for the purpose of limiting fault currents or restricting the fault levels of power station auxiliary systems. The reason for limiting fault levels is to ensure that the system will remain within the fault capability of the power station switchgear and since this has been developed to achieve the comparatively high levels of 750 MVA for 11 kV switchgear and 250 MVA for 276
• Oil-immersed magnetically-shielded coreless. • Oil-immersed electromagnetically shielded coreless. Ideally, current limiting reactors should have no iron circuit because all iron circuits exhibit a non-linear saturating-type characteristic, so that, under the very overcurrent conditions which the reactor is required to protect against, there is a tendency for the reactance to be reduced. Hence, the prevalence of coreless reactors in this list. The cast in concrete variety is therefore aimed at eliminating iron entirely and consists of a series of -
-
Special design features
concrete posts supporting a helical copper conductor arrangement. The problems with these reactors 'result from the fact that they present extremely specialised manufacturing requirements, albeit that they are technically fairly crude. They tend to be sold in such small quantities that it is rarely worthwhile for a manufacturer to maintain the expertise. The major problem is to cast the concrete posts with a sufficiently consistent quality that they can be guaranteed crack-free, particularly since they are arranged in a circle of six, eight, or more, all of which must be made without defects to achieve an acceptable reactor. As a result of the above problems it is likely that enquiries for cast-in-concrete inductors by most electrical plant manufacturers will be rejected. Oil-filled reactors whether with or without an iron core have a number of features in common with transformers, hence most transformer manufacturers are able to design and build them. Reactors with gapped iron-cores are most like transformers in their construction. In a three-phase reactor, a core of superficially similar appearance to a normal transformer core carries one winding on each limb, similar to a transformer winding. The core differs from a transformer core in that 'gaps' are inserted into the axial length of the wound limbs by the insertion of distance pieces made from non-magnetic material — usually pressboard. These normally make up no more than about I% of the iron path length but have the effect of reducing the 'normal' flux density of the device to a level such that, even at fault -
currents of ten or twelve times normal full load current, the core is substantially unsaturated and the reactance is no more than 5-10% less than the value at normal full-load current. Such a device is shown diagrammatically in Fig 3.74.
Like transformers, reactors are subjected to large electromagnetic forces under fault conditions. Since each limb has only one winding, there can be no significant axial unbalance such as can be experienced in a transformer, so there will be no major end forces on winding supports. There remains an axial compressive force and an outward bursting force on the coils. The latter is resisted by the tensile strength of the copper which is usually well able to meet this but the winding must be adequately braced to prevent any tendency for it to unwind. Since reactor windings normally have fewer turns than transformer outer (HV) windings this aspect often requires more careful consideration than for a transformer (see Section 1.4.12 of this chapter). The axial compressive force can, after repeated overcurrent applications, result in a permanent compression of the winding insulation with the result that windings can become loose. This must be prevented by the application of sufficient axial pressure during works processing to ensure that all possible shrinkage is taken up at that time. In a magnetically-shielded coreless reactor, the magnetic shield is arranged to surround the coils in much the same way as the yokes of a conventional transformer core. The shield provides a return path for the coil flux thus preventing this from entering the tank, which would result in large losses and tank heating. The larger the cross-section of the shield the greater is the quantity of iron required, the larger is the tank and oil quantity, and the more costly the reactor. If the shield cross-section is reduced, the flux density under normal rated conditions increases and the tendency to saturate under short-circuit currents is greater, thus bringing about a greater impedance reduction. CEGB practice is to specify that the impedance under short-circuit conditions shall not be less than 90% of the impedance at normal rated current. In many respects the electromagnetically shielded reactor appears the most attractive in that it offers the advantage of constant impedance. In practice, this benefit is usually reflected in the cost. The arrangement of the shield for a single-phase reactor is shown in Fig 3.75. The shield, which may be of copper or -
FLUXES ADD
IJ
FLUXES CANCEL
SHIELD OF CONDUCTING MATERIAL
Flu. 3.74 Gapped iron-core reactor
Fic. 3.75 Electromagnetically-shielded reactor 277
Transformers
Chapter 3
aluminium, provides a path for currents which effectively eliminate the return flux at all points outside the shield. The flow of shield current does, of course, absorb power which appears as heating in the shield. In addition to the balancing effect of the shield currents on flux outside the shield, there is some reduction of the flux within the coil, hence there is a reduction in its reactance. It can be show n, however, that this is independent of the current within the coil and is determined only by the inductance of the coil and the mutual inductance between coil and shield. As in the case of the magnetically-shielded reactor, therefore, there is a need to strike an economic balance between physical size, as determined by the size of the shield, and the unwanted reduction of reactance produced by placing the shield too close to the reactor coil. In practice the effective reactance of the coil and shield combination is made about 90 07o of the coil reactance alone.
and even increasing this to twice its normal value is unlikely to give rise to any particularly searching stress. The usual solution is to apply an impulse test to each line terminal in turn which, as explained in Section 1.4.10 of this chapter, will generate a more significant voltage between turns. The test level is usually the same as would be applied to the same voltage class of transformer. CEGB practice is to apply two full-wave shots preceded and followed by a reduced (between 50 07o and 70%) full-wave application. Other tests are more straightforward and similar to the tests which would be carried out on a transformer, so that a full test series might consist of:
2.6.2 Testing of series reactors
• Zero phase-sequence impedance.
Testing of all reactors can present problems to the manufacturer which are not encountered in the testing of transformers. To a certain extent this results from the fact that they are made in very much smaller quantities than transformers and so manufacturers do not equip themselves suitably to deal with them. Series reactors create two difficulties; one is concerned with proving the performance under short-circuit, the other with proving the adequacy of the interturn insulation. Proving performance under short-circuit not only involves demonstrating that the reactor will withstand the fault currents which are very likely to be a similar magnitude to those in transformers but, for a magnetically-shielded or gapped-cored reactor, also establishing the reactance reduction which occurs under short-circuit conditions. It is rarely possible to measure the impedance at the full short-circuit level, so that the usual approach is to measure impedance at 50%, 75% and 100% of rated current. For three-phase reactors, this is normally obtained from voltage and current measurements taken with the windings connected in star. A curve plotted from these values can then be extrapolated to the short-circuit level. Since this will involve considerable extrapolation (although the iron part of the circuit should operate below the knee point of the magnetising curve — even at the short-circuit current) it is usual, as a type test, to make an impedance measurement on one coil fully removed from the shield. This establishes an absolute minimum impedance which may be used as an asymptote for the extrapolated impedance curve. The normal method of proving the interturn insulation of a transformer is to carry out an induced overvoltage test during which a voltage of twice the normal interturn voltage is developed. Such a test would not be very effective for a series reactor since the 'normal' voltage between turns will be very small 278
• Winding resistance. • Oil samples. • Loss measurement. • I mpedance measurement. • Noise level. • Applied voltage test, including measurement of partial discharge. • I mpulse test. • Oil samples (repeat). • Insulation resistance. • Magnetic circuit and associated insulation appliedvoltage test.
2.7 Instrument transformers 2.7.1 Voltage transformers
As stated at the opening of this chapter, a transformer does not achieve a perfect transformation of voltage and current. The user of a power transformer must accept the facts of regulation and leakage reactance and this he is normally able to do. For instrument transformers, however, these imperfections are less acceptable and the design of the transformer must aim to reduce them to the minimum. Figure 3.76 shows the phasor diagram for a transformer carrying a lagging power factor load 12.11 is the balancing primary current (the diagram assumes unity turns ratio). When added to the magnetising current I c,, this current produces a total primary current I , The secondary induced EMF E2 is modified by reactance and resistance voltage drops to give a terminal voltage lh and, similarly, applied voltage V I results in primary induced EMF E1 . A fuller development of this diagram can be found in any standard electrical engineering textbook. From the diagram, it can be seen that primary and secondary voltages are not exactly in proportion to the turns ratio, neither are they precisely in opposition to each other. The differences are known as the ratio error and phase angle error respectively.
Special design features
En, 3.76 Phasor diagram for transformer with lagging power-factor load
Voltage transformer accuracies require the designer to restrict these errors to known small quantities. This is possible provided that the transformer is operated vothin strict limits. The most significant of these limits is the load applied to the voltage transformer which is expressed in VA and known as the burden, but it is also necessary to ascertain that applied voltage, frequency and power factor are within the bands prescribed by the transformer designer. The limits on phase-angle and ratio error are usually defined by specification and for voltage transformers used within the CEGB BS3941 1975 [17j is the applicable standard. BS3941 classifies voltage transformers in accordance with their percentage voltage ratio error and with the use to which they are to be put. Voltage transformers used for measurement purposes ma ■. provide a signal to tariff metering equipment or they may be used to control equipment associated with a generator AVR or a transformer onload tapchanger. Such signals are required to have high accuracy and five classes of measuring voltage transformer are defined having voltage ratio errors ±0,1, ±0.2, +0.5, +1.0 and +3.0%, the individual classes being identified by the use of a number equal to the percentage voltage ratio error. Thus accuracy class 0.1 defines a voltage transformer having ratio error within +0.1% of nominal. Voltage transformers used in protection schemes do not require such a high degree of accuracy. Usually these are feeding equipment which simply requires to
know whether a supply is energised or not, for example, no-volt relays, although occasionally wattmetric equipment might be involved such as low forward power, or reverse power relays (see Chapter 11). Protective voltage transformers having errors of +3.0 and ±6.0% are defined in BS3941. These are identified in a similar manner to measuring voltage transformers but the designation is given in addition to a suffix letter P. Hence class 3P defines a protective voltage transformer having voltage ratio error +3.0%. The voltage error limits given above for measuring voltage transformers apply over the range 80ro to 120% of rated voltage with burdens of between 25 07o and 100% rated burden, at a power factor of 0.8 lagging and at rated frequency. Many forms of protection require a voltage transformer capable of reproducing the primary phase-toearth voltage. This is provided most conveniently using single-phase units connected between line and earth. This can, however, create problems for the voltage transformer designer, depending on the system earthing conditions. When there is a single-phase to earth fault on the system to which the transformer is connected, there is also an increase in the voltage to earth of the sound phases which thus imposes an overvoltage on the VTs associated with those phases. The transformers experience an increase in flux density in the core, with a resulting increase of magnetising current flowing in the primary winding. Both of these could produce overheating, unless the transformer is suitably designed. The same effect would occur in a three-phase star connected transformer and, in addition, a residual flux would be produced by the unbalanced voltages. This flux cannot be contained within a normal three-phase three-limbed core, so such transformers must have three separate single-phase cores (making them virtually singlephase transformers) or incorporate extra return limbs, or employ a shell-type core construction as shown in Fig 3.77. The magnitude lnd duration of the increased voltage depends on the method of system earthing and the type of protection against earth faults. BS3941: 1975 therefore defines a rated voltage factor for all voltage transformers which varies from 1.2 continuous for VTs connected between lines in any network to 1.9 for 8 h for VTs connected between line and earth in an isolated neutral system without automatic earth fault tripping. Note that the use of voltage factors even as high as 1.9 does not affect the insulation level requirement of a VT. Insulation level is based on system highest voltage which is related to the highest voltage that can occur between lines: this is normally greater than that occurring between line and earth, 2.7.2 Generator voltage transformers
The most important voltage transformers on a power station system are those connected to the generator 279
Transformers
FR:, 3.77 Shell-type core construction for a protection VT
busbars. These provide signals to the automatic voltage regulator (AVR), protection equipment, metering and synchronising equipment. As indicated in Section 1.6.9 of this chapter, they can also be used to initiate automatic control equipment, such as that associated with the generator transformer cooling. Single-phase voltage transformers are used for the reasons discussed above, and also to make possible a totally phase-isolated system of connections to the generator terminals (see Chapter 4). On a modern 660 MW generator, four sets of such VTs are used, and connected as shown in Fig 3.78. The generator voltage system is high-resistance earthed at the generator neutral (see Section 2.5.1 of this chapter and Chapter 11), so the CEGB specifies a rated voltage factor of 1.9 for five minutes. This apparently long duration was selected when high-resistance earthing of the generator neutral was first introduced, the stator earth fault trip was made an unloading trip, i.e., the generator circuit-breaker was not opened until after the turbine throttle valves had been closed to reduce the load to zero. Whilst the unloading trip is no longer used, the timescale has been retained for the purposes of standardisation and interchangeability. For a generator voltage of 23.5 kV, the VTs have a primary rated voltage of 221./3 kV and a secondary rated voltage of 110/./3 V. This gives a rated transformation ratio of (22 000/V3)/(1 101.13) resulting in \.oltage ratio of 200 to 1, which is a simple round number. Reference to BS3941, Table 1 (Rated transformation ratios) shows that standard practice is to specify transformation ratios for single-phase VTs in this way, using secondary voltages of 110/V3 and primary voltages which are multiples of eleven, also ided by ./3. It will also be seen from Fig 3.78 that the transformers are provided with tertiary windings, which 280
Chapter 3 can be connected in open-delta. The reason for this is now largely historical and originated with the objective of providing protection against neutral instability, also sometimes known as 'neutral inversion'. This can arise on the neutral of the generator voltage system when it is earthed only via the star point of the generator VTs and when the VT magnetising current, which is highly inductive, is of the same order of magnitude as the capacitive current to earth in the generator windings. A resonance is thus produced which can result in high voltages between phases and earth, resulting in breakdown of the generator neutral. The problem can be avoided by high-resistance earthing of the generator neutral, which is now standard practice for other reasons (Chapter 11), and by ensuring that the VT works at a sufficiently low flux density so that it is always on the linear part of the magnetising curve and there will be no chance of saturation. This is good VT design practice anyway, and is done to ensure that the magnetising current is low to minimise transformation errors. However, provision of a tertiary winding costs very little and, in order to allow standard interchangeable VTs to be used, one is provided on each. Provision of the connections to enable the tertiary windings of only one set of VTs to be connected in delta is, of course, all that is required from the external wiring and it is CEGB practice to install this only to the tariff-metering VTs as indicated in the diagram. As mentioned above, it is desirable that all generator voltage transformers should be identical, so it is CEGB practice to specify that these should have a dual 50/150 VA rating with high accuracy (Class 0.2) at the 50 VA rating required for the supply of the AVR and metering equipment, and the lower accuracy (Class 1 and Class 3P) at the 150 VA rating appropriate to the protection duty. The insulation system used for generator voltage transformers is cast-resin and, since the 1970s, HV, LV and tertiary windings have all been encapsulated. Solid insulation is used in preference to oil, since it avoids any material having a fire risk being in the vicinity of such high integrity plant as the main turbinegenerator. The advantages of cast-resin in preference to dry-type class C insulation are discussed in Section 2.4.2 of this chapter. The group of four voltage transformers for each phase is protected by a 10 A fuse fitted at the point where the voltage transformer tee-off is made to the generator phase-isolated busbars. Phase isolation is maintained throughout the tee-off (see Chapter 4) and each voltage transformer is protected by an individual 3 A fuse at the point of further sub-division from the tee-off. These can be identified in Fig 3.76. The voltage transformer is housed within a 'drawer' or 'drum' so that it can be withdrawn and isolated from the generator voltage system whilst the latter remains energised. The act of withdrawal brings about automatic earthing of the primary line connection, on both sides of the 3 A fuse, and also earths all secondary connections.
Special design features Fuses for secondary and tertiary windings must be mounted as close as possible to the winding terminals, since any wiring between winding terminal and fuse is unprotected. The impedance of the voltage transformer is such that the primary 3 A fuse does not provide protection against secondary or tertiary wiring faults. In addition to the need to ensure that the VTs themselves have the highest possible integrity, it is important that the likelihood of faults on any equipment connected in the vicinity of the generator busbars should be made as low as possible because of consequential damage that can be caused by such faults. Normally, a voltage transformer having resin-encapsulated windings will have an external, non-encapsulated, core having steel channel sections to apply clamping pressure. It is usually convenient to mount secondary and tertiary fuses, links and earth links within one of these channels. Such an arrangement is seen in Fig 3.79, which shows the completed installation for a 660 MV generator; the fuses and links, etc., are concealed behind the cover plate in the foreground. 2.7.3
Current transformers
For all transformers discussed thus far, it is the case that events occurring in the secondary circuit are reflected in the primary, changed only by a factor dependent on the transformation ratio: a short-circuit of the secondary appears as a short-circuit to the primary supply, open-circuiting the secondary appears as an open-circuit to the primary supply. A current transformer is fundamentally different since no event occurring in the secondary circuit can in any way affect the current in the primary. The purpose of this volume is to deal with practical aspects of power station plant and reference can be made to any standard textbook for most areas of electrical theory. It is however necessary to examine transformer theory as it is applied to current transformers M some detail in order to appreciate this fundamental difference and the significance of the various design features. The following few paragraphs will attempt to do this. The reader will find a more exhaustive treatment in 'Current Transformers, their transient and steady state performance' by Arthur Wright (18]. The phasor diagram of a current transformer is shown in Fig 3.80. The resistance and reactance drops in the transformer and the magnetising current play their part in determining the dispositions of the various phasors, as in the case of a voltage transformer, but their relative values and the significance of the various phasors are very much different. Figure 3.81 represents the conventional equivalent circuit for a transformer for which the primary winding resistance and reactance are negligible. This is a valid assumption for a current transformer whose inclusion does not have any effect on the current flowing in the primary circuit. Other circuit values as indicated in the diagram are as follows:
LM
Magnetising inductance
R2
Secondary resistance
R p Resistive component of core loss L2
Secondary inductance
1
RMS value of exciting current
0
lp
RMS value of resistive component of exciting current
I n„
RMS value of magnetising component of exciting current
Ni Number of turns on primary winding N2
Number of turns on secondary winding
et
EMF induced in primary winding
e2
EMF induced in secondary winding
ZB
Burden
From the equivalent circuit, the exciting current of the transformer is dependent on both the impedance of the magnetising 'branch' and the EMF required to drive the secondary current through the total secondary circuit impedance. Because the secondary current of a current transformer may vary over a wide range, from zero under no-load conditions to very large values under primary system fault conditions, the exciting current also varies greatly. This represents a significant difference between current transformers and voltage transformers since the latter operates at almost constant excitation current under all normal conditions. In a properly designed current transformer loaded with its correctly rated burden, the secondary EMF required to circulate secondary rated current will be low enough to ensure that the core does not approach saturation. Nevertheless, the exciting current will have a non-sinusoidal waveform. Since at any instant the total ampere-turns provided by primary and secondary windings must equate to those required to excite the core, then on the assumption that the primary current is sinusoidal, the secondary current must contain any harmonics. The degree of distortion of the secondary current waveform will, however, be less than that of the exciting current since the magnitude of the latter will be small in relation to the secondary current under all normal conditions. Considering the phasor diagram of Fig 3.80, it can be seen that the error in the current transformation ratio is created by the exciting current. Once the exciting ampere-turns have been determined, therefore, the error can be obtained by comparing the exciting ampere-turns with the primary ampere-turns. However, if the exciting current is non-sinusoidal, it is difficult to express the error in precise terms since, although its RMS value can be calculated, it is difficult to assign a phase angle relative to the primary or secondary current. For this reason, it is the accepted practice to express errors in current and phase by assuming that the exciting current is sinusoidal 281
Chapter 3
Transformers
7
GENERATOR VTs
E , K.C'ENC TES T kIETER ING
THREE SINGLE PHASE VTs CONNECT.GNS IDENTICAL TO THOSE BELOW
OPERATED
S.NOLE
sy4
TF-IAUE
T
CUBICLE ATE SS TE • , INTERLOCK TWITCH
--e 3A
-
• 7.4
6.A
-
5A
_ 22H
1 0
.0 110
E:' I
4A
4A
rARIFIT METEANG IN sTauMENTS AND FUSE PAL mONITORING
—
--0 I 0— — E35.T.
I
0 47
— —0 I 0— — E I
-
—
AUTOMATIC VOLTAGE REGULATOR CHANNEL A AND PROTECTION
THREE S.NGLE EVADE VT5 CONNECTIONS GENT CAL TO THOSE ABOVE 1.1..•■•■
■■■•■ ■■
.
•••■•■
■1■■••.
, 'MPH SIN3,Z . 111SE
CCNNECT.ONS .DENT.C TO ABOVE
,,
AUTOMAT:C. VOLTAGE REGULATOR CHANNEL
L
e AND PROTECTION
1
*EAP..I'EvC
DELTA EL:PCEN:S.JSE 2
FIG. 3.78 Generator VT connection arrangement
282
Special design features
GENERATOR Yrs DISTRIBUTION BOARD E2T: -
A.P
:
A
I RELA , -
qELA, 55
r.1 E.TIAwA
_i
_ _ — ,,
-&'
!.:EGA.VATT ND.EATIDNS LO5C CONTROL 2
s, lEON. AN 5 .1 - ac,. •
L.7.AE
I
I
I
T Ar, '
TARIFF METERING
riCA
■
1 SA l L A '
SRNCYPONPSINC.
/ EJ65
I OPP: DELTA BURDEN IF RECL , PED
I -- —. ---
---
-0- - - - - - - - - - - - - - - - E E5. --
ET.
E
'
, Ail T OMA 'DC vOLTAGE REGULATOR CHANNEL A
J. .1 TECiF.AL
FiLfYiNG CONTROL O AND FUSE PAIL DEL, CE
I
OVEFIFLLAING PROTECTION MO.TNTED ON RELAY °ANEL POLE SLIPPING PROTECTION OVER UNDER FREOUENCY PROTECTION S. VOLTAGE ELIPFA_Y SLIPER'i!SIGN RELAY
I
' 24 '
I2
I
Li" L., -
-
I
I
2A '
I
1:DVERFLUXING PROTECDO- N AuTC3:,9ATIC +TC, LTAGE VOUNTED ON RELAY PANEL PEGLILATCP CHANNEL LOSS OF EXCITATION , pc:01N.:C 'NON DIRECTIONAL .t:TE;RRAL :ERF,WONG CONTROL I CVEPCLiPPENT PROTECTION AND TL.rSE DE EP VOLTAGE SUPPLY 51;P•TRyisirrN 4 R",
I
LOW FORwAn. POWER RELAY ANL) VOLTAGE SUPPLY SUPERVISION RELA' ,
I LOLA FORWARD
Pov..ER RELAY SUPPO' SUPERV I SION RELAY
FIG. 3:78 (cont'd) Generator VT connection arrangement
283
Chapter 3
Transformers
Phase angle error
0 Flu. 3.80 Phasor diagram for current transformer
(N 2
p4 1 )2
z
Load
Flo. 3.79 Generator voltage transformer 0
(except in certain specific circumstances, which will be dealt with later). The amount by which the transformation ratio departs from the ideal value is: [(Ka — Kn)/K,J 100%
(3.9)
where K T, is the turns ratio of the ideal transformer, given by N2/N1 and K a is the effective turns ratio given by 11/12.
It should be noted that this differs from the definition of current ratio error given by BS3938: 1973[19J which is: 0 (3.10) [(K0I2 — Ii)/II] 100 7o i.e., the current which is assumed to be flowing in
the primary on the basis of the measured current in the secondary (I2), minus the current actually flowing (1 ) divided by I. This becomes [(Kn
—
Ka)/K a ] 100%
(3.11)
MIMI is not the same as Equation (3.9) but, since the difference between K n and K a is usually small compared with both K, and K a , for practical purposes this will appear the same. The term 'current ratio error' is often abbreviated to simply 'ratio error'. The phase angle error is the angle between the phasors representing the primary current and the secondary current reversed. This is conventionally taken as 284
PRIMARY SUPPLY VOLTS
FlG. 3.81 Conventional equivalent circuit for
transformer
positive when the secondary current phasor reversed leads the primary current phasor. Since there is a wide band of primary currents within which the transformer will operate below saturation then, provided the secondary current remains within that determined by the rated burden, it is possible for the current transformer designer to make some correction for the ratio error. For example, if it were required to design a CT having the ratio 1000: I, and over the operating range the ratio error varied in magnitude between 0.2% and 0.5% then, by using 998 turns on the secondary for a single primary turn, the actual error over the operating range would be minimised. From this, it will be seen that the larger the number of primary turns, the greater the accuracy with which compensation can be carried out. Such compensation does not, of course, affect the phase-angle error. It will be evident from the above that reduction of the current and phase angle errors can be obtained for any given operating condition by reducing the exciting
Special design features ri.•
ampere-turns in relation to the secondary winding ampere-turns. This can be achieved by shortening the flux.path and increasing the cross-sectional area of the core. Hence, ideally, a ring construction having the smallest practical diameter and greatest practical crosssection should be used. A significant reduction in errors can be achieved by increasing the number of turns on primary and secondary windings. The reason for this is that, assuming no change in burden, the secondary EMF necessary to circulate the required secondary current remains constant. However, if this is induced into an increased number of turns, the volts/turn are reduced, the flux density is reduced and hence the exciting current, which is the source of the error, will be reduced. It can be shown that provided operation is within the linear part of the magnetisation curve, the error is approximately inversely proportional to (turns) 2 . This is an approximate relationship since, as with power transformers, no parameter can be changed in isolation from all others. Increasing the number of turns inevitably increases the resistance of the secondary winding, thus needing an increased EMF to circulate the required current. This can be offset by increasing the conductor cross-section but since this itself increases the length of mean turn, only partial benefit results. The above also emphasises the benefits to be gained by minimising secondary burdens so that, although the impedance of relays or other equipment cannot be changed, leads can be made as large as practicable, thereby minimising voltage drops. At this point it is appropriate to identify and examine the different requirements of current transformers for measurement and protection purposes. BS3938: 1973 defines the accuracy classes of measurement current transformers in much the same way as does BS3941 for voltage transformers. Classes 0.1, 0.2, 0.5, 1, 3 and 5 have permitted current errors of ±0.1, ±0.2, ±0.5, ±1, ±3 and ±5% respectively at 120 070 of rated current. (Permitted errors are also quoted for intermediate currents. The full range is shown in Tables 3.3 and 3.4.) The performance during fault
••■••
■•
or transient conditions is not of interest for most measurement applications; in fact it might be advantageous if the CT saturates under these conditions, since this limits the overvoltage applied to the connected equipment. For protective current transformers, the performance under fault conditions is critical and for these the concept of composite error is introduced in BS3938. This is defined as:
100
(3.12)
p
where the symbols and suffixes have the same meanings as defined above except that i, and i p are instantaneous values. T is the period of one cycle of the supply. As can be seen, this expression has the form of an RMS quantity and takes into account the harmonic content and phase shift of the secondary current. Composite error is defined at the rated accuracy limit primary current which may be several times the rated primary current. The ratio of accuracy limit current to the rated current is known as the accuracy limit factor. Protective CT classes are defined in accordance with their permitted composite errors and BS3938 lists Classes 5P and 10P having composite errors of 5 and 10 07o respectively. The corresponding permitted current errors at rated current are ± 1% and +3%. For protective CTs, a high degree of absolute accuracy is not important, provided that a reasonable degree of accuracy is obtained at the required overcurrent level. For this reason, turns compensation is not generally applied to such transformers. The above remarks are mainly applicable to protective CTs used for overcurrent protection. For most other protection applications, the most important feature is the maximum useful EMF which can be obtained from the CT under system fault conditions. In this context BS3938 defines the knee point EMF of
TABLE 3.3
Limits of error for current transformers accuracy for Classes 0.1 to 1 ± phase displacement at percentage of rated curren shown below
± percentage current (ratio) error at percentage of rated current shown below
minutes
Class 10 up to but not incl. 20
20 up to but not incl. 100
100 up to 120
10 up to but not incl 20
centiradians
20 up to but not incl 100
100 up to 120
10 up to but not incl
20 up to but not incl 100
100 up to 120
8
5
0.3
0.24
0.15
0.1
0.25
0.2
0.1
10
0.2
0.5
0.35
0.2
20
15
10
0.6
0.45
0.3
0,5
1.0
0.75
0.5
60
45
30
1.8
1,35
0.9
2.0
1.5
1.0
120
90
60
3,6
2.7
1.8
285
Transformers
Chapter 3 TABLE 3.4
Limas of error for current transformers accuracy for Classes 3 and 5
Class
± percentage current (ratio) error at perc ntage of rated current sh own below 50
ferably located as close as possible to the generator busbars to minimise the length of leads required to carry 20 A.
References
3 [11
British Standards Institution: BS171: Specification for power transformers: 1970
121
Blume L. F., Boyajian A., Carnifli G., Lennox T. C., Mined S. and Montsinger V. M.: Transformer Engineering: John Wiley and Sons
(3 1
British Standards Institution: BS1432: Specification for copper for electrical purposes. Strip with drawn or rolled edges: 1970
100
3
3
3
5
5
5
Montsinger V. M.: Loading transformers by temperature: Trans. AIEE Vol 49 pp 776: 1930
the CT as 'That sinusoidal EMF of rated frequency applied to the secondary terminals ... which, when increased by 10 6/o, causes the exciting current to increase by 50 07o'. CTs specified in terms of knee point FMF (as well, of course, as rated primary current and turns ratio) are designated Class X Protective Current Transformers by BS3938 and are permitted a turns ratio error of +0.25 07o.
BS Code of Practice CP1010: Loading guide for oil-immersed transformers: 1975 Shroff D. H. and Stannett A. W.: A review of paper aging in power transformers: Proc. 1EE, Vol 132, Part C, No.6: November 1985 Franklin A. C. and Franklin D. P.: The 3 and P Transformer Book, 11th Edition: Butterworths: 1983 British Standards Institution: BS5750: Quality systems: Part 1: Specification for design, manufacture and installation: 1979 Part 2: Specification for manufacture and installation: 1979 Part 3: Specification for final inspection and test: 1979 Part 4: Guide to the use of BS5750, Part 1: 1981 Part 5: Guide to the use of BS5750, Part 2: 1981 Part 6: Guide to the use of BS5750, Part 3: 1981
2.7.4 Current transformer construction Current transformers for measurement and protection purposes are required throughout a power station auxiliary system. Most frequently it is convenient to locate these within switchgear, for which the barprimary arrangement is the most suitable in terms of strength and simplicity. Current transformers used on generator voltage busbar systems are also, in effect, bar-primary devices with features developed specifically to meet the requirements of the system. Figure 3.69 shows current transformers at the neutral end of a 660 MW generator. It is necessary to wind the secondary turns on the very large diameter toroidal core in order to provide the air clearance required to meet the 70 kV power frequency, 170 kV impulse-withstand insulation levels of the generator busbars. For a 660 MW machine, the rated busbar current is 20 000 A so that, if the final secondary current is to be 5 A, a ratio of 20 000: 5 is required. With a bar-primary, 4000 secondary turns would thus be needed and some manufacturers consider it more economic to carry out this transformation in t wo stages. Main CTs installed at the generator busbars having a ratio of, say, 20 000: 20 are used in conjunction with additional interposing transformers of ratio 20 5. The interposing transformers are pre-
286
19J International Electrotechnical Commission: Publication 76, Power Transformers [10] British Electricity Boards Specification: BEBS-T2: Specification for transformers and reactors: 1966 111] The Electricity Council: Document IT: Guide on impulse testing power transformers and reactors [12] British Standards Institution: BSI48: Specification for unused mineral insulating oils for transformers and switchgear 1984 [131 Wilson A. C. M.: Insulating liquids and their uses, manufacture and properties: Peter Peregrinus Ltd 1141 The Electricity Council: Recommendation G.5/3: Limits for harmonics in the UK electricity supply system: September 1976 [15]
Corbyn D. B.: This business of harmonics: Electronics and Power, Vol 18 pp 219-223: 1972
[16]
The Electricity Council: Report ACE15: Harmonic distortion caused by converter equipment
[17]
British Standards Institution: BS3941: Specification for voltage transformers: 1975 (1982)
[18]
Wright A.: Current transformers, their transient and steady state performance: Chapman and Hall Ltd
[19]
British Standards Institution: BS3938: Specification for current transformers: 1973 (1982)
CHAPTER 4
Generator main connections 1 Introduction 1.1 Evokition 2
Principles of isolated phase busbar operation and forces encountered 2.1 Principles 2.2 Forces 2.3 Voltage rise
3
Designing an IPB system
4 Forced cooling 4.1 Forced air cooling 4.2 Liquid cooling 4.3 Water cooling 5 System description 5.1 Line end 5.2 Neutral end 5.3 Tee-offs 5.4 Delta connections 5.5 Excitation busbars 5.6 Earth bar 6 Setting out the specification 7 Component parts of an IPB system 7.1 Conductor and enclosures 7,2 Equipment enclosures 7.3 Insulators 7.3.1 Post insulators 7,3.2 Foot insulators (including enclosure supports) 7.3.3 Disc bushings 7.3.4 Wall seals 7.3.5 Bellows 7.4 Conductor and enclosure expansion joints 7 5 Flexible connectors 7.5.1 Flexible laminae connectors 7.5.2 Braided flexible connectors 7.6 Painting 7.7 Conditioned air 7.8 Voltage transformers
1 Introduction The principal function of the Main Connections Busbar System is to connect the generator to its associated generator transformer and, incidentally, to provide a convenient means of connecting the Unit electrical system to the Unit transformer, via a tee-off. It is present day practice, for reasons explained later, to use an aluminium tube for each phase conductor (or
7.9 Current transformers 7.10 Environmental conditions 7.11 Portable earth access covers 7.12 Viewing ports 7.13 Connection of the conductor to plant 7.14 Joints in the conductor 7.15 On-load temperature measurement 7,16 VT cubicles 7.17 Access platforms 7.18 Structural steelwork 7.19 Neutral earthing equipment 7.20 Site installation 7.21 Quality assurance 8 Testing 8.1 Tests on component parts 8.1.1 Insulators and bushings 8.1.2 Busbar material 8.1.3 Transformers 8.1.4 Loading resistors 8.1.5 Capacitors 8.1.6 Switchgear and earthing switches 8.1.7 Compressed air system 8.2 Tests on representative sections of IPB 8.3 Test levels 8.4 Tests at site 9 Experience of testing 10 Generator voltage switchgear 11 Earthing 12 Earthing for maintenance purposes 12.1 Primary earth 12.2 Portable drain earths 13 Protection 14 Interlocking 15 Future trends 15 References
busbar), which is surrounded by a concentric enclosure of the same material and similar conducting crosssectional area; each is effectively isolated from its neighbour, hence the term isolated phase busbar (IPB). British practice (1988) uses dry conditioned air at a pressure slightly above atmospheric as the insulating medium between the conductor and enclosure. The conductor is supported at the centre of the enclosure by insulators; these are equispaced and rigidly 287
Chapter 4
Generator main connections fixed around the circumference of the enclosure but allow limited radial movement of the conductor. The rating of the main connections installation is established on the basis of temperature rise above a specified ambient at maximum commercial load and its ability to withstand both three-phase short-circuit and earth fault conditions anywhere on the generator voltage system without damage. These requirements introduce some complication in the system design in order to achieve high integrity. Isolated phase busbars have evolved over a number of years, having originally been pioneered in the USA and further developed in France before their introduction in the UK in the mid-1960s. They represent 3-4% of the total cost of the connected generator and transformers. A typical installation is shown in Fig 4.1.
1.1
tor, primarily on economic grounds, once aluminium welding techniques had improved. The duct or enclosure only excluded gross pollution and prevented physical contact, giving no protection against phaseto-phase faults or the electromagnetic forces between conductors. Strong magnetic fields from this arrangement could cause overheating of external steelwork adjacent to the busbars, increasing system losses. As currents increased, phase barriers made of either a metallic or insulating material were introduced to li mit the consequences of phase-to-phase flashover (Fig 4.2 (b)). Further improvement was achieved by the use of phase segregation, using a continuous metallic fabricated-aluminium enclosure and barrier, the barrier being integral with the enclosure (Fig 4.2 (c)). Whilst phase segregation offered an improved design compared with the original common enclosure, it still had a number of weaknesses. Phase-to-phase faults were still possible because adjacent phase conductors share a common barrier. Complicated circulating currents in the enclosure produced forces between conductor and enclosure because no attempt had been made to isolate the busbars magnetically, and the assembly generally became large and exacting to construct. Such designs were used for generators up to 500 MW before new designs were introduced to deal with the shortcomings of phase segregation. These are insulated by enclosing each phase in its own conducting metal tube separate from its neighbours; hence the name isolated phase busbars'. In an installation of this type, eddy currents are induced in the enclosure, or sheath, due
Evolution
There has been extensive development of generator connection designs since their introduction because of larger generating sets and the consequential increase in load and fault currents. Clearly a cable connection to the machine is simplest, but both current and temperature limit their use to about 120 MW (assuming a generator terminal voltage of approximately 23 kV). Consequently, for larger machines, three bare copper conductors (one/phase) were introduced, supported by single insulators at regular intervals and enclosed within a common duct or enclosure (Fig 4.2 (a)). Aluminium gradually replaced copper for the conduc-
Figl
if EXCITER CONNECTIONS r,
i
NEUTRAL CONNECTIONS
\
EARTH SWITCH
\
GENERATOR \ CONNECTIONS
t-,
It io
lir
lik
,A... ..),--, -. :a., ,...\ 1 i, I
VT CUBICAL EXCITER FIELD SW/TCH
ni
ISOLATED PHASE ASSEMBLY
EXCITER NEUTRAL RECTIFIER EARTHING MODULE
FIG.
288
UNIT TRANSFORMER EARTHING TRANSFORMER
4.1 Generator main connections — general arrangement of a typical installation
Principles of isolated phase busbar operation and forces encountered
OUCT OR ENCLOSURE CONDUCTOR SUPPORT INSULATOR
z
1NTERPHASE BARRIERS ,r. ETALLIC OR INSULATING,
^+E., -& ea
,
egalea DS
Darr.er$
CONTINUOUS METALLIC FABRICATED ENCLOSURE aNCUJOING BARRIERS
fault conditions the reactor saturates, reducing its impedance to circulating currents and allowing greater enclosure current to flow. As will be explained later, this enclosure current reduces the forces between conductors during fault conditions. However, in practice, the reactors tended to burn out, so now only the electrically-continuous 1PB with short-circuit is considered in the UK and elsewhere. These, by virtue of the enclosure circulating currents, limit forces between phase conductors to approximately 10 07o of those that would exist without the enclosure. The enclosure system is earthed at one point only and is insulated from earth along its length by supporting it on insulated foot mountings, thereby giving control over the path followed by any fault current in the enclosure. Clearly the main connections have now become a system in their own right and to control the circulating currents, as described, the enclosures must be isolated from all items of plant to which the conductors are connected. Enclosures are therefore connected to auxiliary plant via rubber bellows which maintain the physical protection of the conductor but isolate the enclosures electrically from the plant. The bonding or short-circuiting of the enclosures is done as close to the end of their run as possible. The external magnetic fields produced by the conductor currents can link with conducting loops in the adjacent steelwork, producing circulating currents and heat. This is a problem to be considered by the designer since excessive heat,
in addition to being an unnecessary system loss, can cause unacceptable expansion and can be a hazard to Ph3se seg•egated sus
FIG. 4.2
C;
\ INSULATING FEET
Segregated and non-segregated busbars
to the conductor current, and this to some extent shields I he
forces between the conductors by modifying the field around the conductor. There are, however, still substantial magnetic fields outside the enclosure, which produce forces between phases. These are reduced considerably if the extreme ends of each phase enclosure are bonded together, thereby allowing a balanced current flow in the enclosures of all three phases. This system is known as an 'electrically continuous IPB with short-circuit' (see Fig 4.3). Each phase enclosure is made electrically continuous throughout its length and all three are connected together at both ends of the run. This distinguishes it from other systems, namely the insulated type (where the enclosure is not continuous hut includes non-conducting sections) or the continuous [ Me with saturable impedance, where the continuous phase enclosures are connected together at the ends of the run through small saturable reactors which limit the induced longitudinal currents to a design value. The last-named appears attractive because the reactor limits the enclosure circulating currents during normal operati on, thereby reducing the enclosure losses, and during -
personnel if the steelwork is touched. Machines of 660 MW are now used extensively in the UK and an IPB installation of the type described provides an adequate main connections design which can be naturally cooled and is of manageable size. This probably represents the limit of naturally cooled designs and any significant increase in machine rating will mean that forced-cooled designs will have to be considered. The components of one phase of such a system are shown diagrammatically in Fig 4.4.
2 Principles of isolated phase busbar operation and forces encountered
2.1
Principles
Consider, using simple analysis, how the magnetic fields may be reduced. When a conductor carries an alternating current, it produces an external concentric alternating magnetic field, the direction of which is determined by application of the 'corkscrew' rule. If another conductor runs parallel to it, then an EMF is induced in it, given by e = — (c1(1)/dt), where cl) is that proportion of the flux linking the two conductors. The negative sign indicates that it tries to oppose the force which created it. 289
Generator main connections
Chapter 4
FG. 4.3 Phase isolated busbar — continuous sheath
For a length of isolated phase busbar, the voltage Se induced in an elemental section of non-continuous sheath (say, SA and SB in Fig 4.5 (a)) due to the current flowing in its associated conductor will be the same magnitude for all elements on the circumference of the sheath at any point along its length. It follows, therefore, that one phase in isolation can have no current flow in the sheath, since the voltages at all points are equal. If next, the condition in Fig 4.5 (b) is considered, the voltage e induced in an elemental section of noncontinuous sheath due to the current flowing in an adjacent conductor will be of different magnitude for each position around the periphery (say, SC and SD), since each element cuts a different proportion of flux from that conductor. Therefore, unequal voltages are available to cause current to flow in the sheath as shown in Fig 4.6 (a). This sheath current, which for the elemental circuit shown in Fig 4.6 (a) can be considered as a simple `go' and 'return' circuit, will set up an electromagnetic field whose direction can be determined by application of the corkscrew rule. This will give rise to a reduction of field within the enclosure but a reinforcement of the field outside as shown in Fig 4.6 (b). Thus the, e is a reduction of forces between the conductors and an increase in forces exerted on the enclosure. The enclosure will therefore need substantial supports. The currents circulating in each sheath caused by the proximity effects of adjacent conductor systems are termed 'eddy currents'. Formulae for determining these currents and their associated losses have been proposed by H. B. Dwight in 1923 and F. W. Carter 290
in 1927. In the paper by Carter [I], the eddy current was determined by considering the fixed distribution of conductor currents but taking into account the magnetic field set up by the induced eddy current in the sheath itself. This first order eddy current was then determined for neighbouring sheaths and these were used as a fixed distribution to obtain second and further subsidiary eddy currents in the original sheath. The process may be repeated to any degree of approximation to obtain a total eddy current. In Dr Carter's day, the problem did not merit meticulous calculation and the treatment was therefore simplified by considering only the first order eddy current to produce results in a convenient form for hand calculation. Working independently, Dr Dwight tackled a number of proximity effect problems and in 1923 published a first order eddy current solution [2] for sheath eddy loss which is identical to the Carter solution. Later, in 1964, the analysis was extended to determine the subsidiary eddy currents for the particular case of a single-phase circuit and also a three-phase flat grouping. Since the non-continuous type of IPB is not used by the CEGB, the theory is not developed here, but the reader may deduce the necessary formulae from papers [1 and 2]. Now consider the continuous type of IPB. If the sheaths of all three phases are electrically connected at each end of the IPB run, an external path is provided which allows the sheath currents to flow in the manner shown in Fig 4.3. The phase conductors and the enclosures are comparable to the primary and secondary turns of a short-circuited transformer. The
TRANSFORMER END
GENERATOR END
ENCLOSURE EXPANSION JOINT FOUR SETS OF FIVE FLEXIBLE BRIDGING STRAPS
NEOPRENE BELLOWS
-
MAIN CONDUCTOR EXPANSION JOINT
11". .- ._
INSULATOR
1
GENERATOR MAIN TERMINAL CONDUCTOR STALK
din7 I__ II!
Str .
.......1
000
"1".1
TERMINAL CANDELABRA CONNECTIONS ( ONLY 3 SHOWN)
Jr. INSULATED FOOT
SUPPORTING STEELWORK DISC BUSHING
BELLOWS
NOTE THIS IS A DIAGRAMMATIC COMPOSITE TO ILLUSTRATE THE MAIN SYSTEM COMPONENTS IT IS NOT A TYPICAL ARRANGEMENT AND IS NOT DRAWN TO SCALE
CONDUCTOR TERMINAL PALMS (EIGHT OFF)
TRANSFORMER BUSHING
Fici. 4.4 Phase isolated busbar — main components
Principles of isolated phase busbar operation and forces encountered
va ""---
ENCLOSURE
Chapter 4
Generator main connections
• B
•
• Al nil
O.,
•
• •
• •
•
•
;a) induced voltages in an enclosure due to its own conductor
•
•
• .c
•D •
•
CD
0 •
• •
•
• a
(b) Induced voltages in an enclosure due to an adjacent conductor Fin. 4.5
Induced voltages in an enclosure
magnetic field produced by the primary conductor induces a current of opposite direction in the secondary turn. The magnitude of the circulating sheath current is almost equal to the conductor current, depending on the resistance and reactance of the enclosure circuit, and is in antiphase to the conductor current. The sheath current usually amounts to about 90% of the conductor current. The circulating sheath current creates its own surrounding magnetic field which must be in antiphase to that produced by the conductor, thus the magnetic field still exists within the enclosure but is cancelled outside it (see Fig 4.6 (c)). Since the enclosure has resistance, the resultant external magnetic field around each conductor is about 10% of that which would occur if there was no metallic sheath. Since the external magnetic field has been reduced, it follows that the forces between conductors are also reduced by a similar proportion, as will be the forces between enclosures that exist due to the current flowing in them. However, end effects occur where the conductor is connected to its associated piece of plant and is, for practical reasons, unshielded. Therefore magnetic fields at these points are much stronger and forces greater. For further analysis, the reader is referred to a paper by Skeats and Swerdlow [3].
2.2 Forces The forces caused by short-circuit and earth fault currents are very complex. Neglecting decrements, a totally-offset short-circuit current can be represented
ENCLOSURE EDDY CURRENTS
(a} Enclosure eddy currents in a phase isolated buster • dscontinuous sheath
FIG. 4.6 Radial current flows due to current in an adjacent conductor 292
Principles of isolated phase busbar operation and forces encountered
CONDUCTOR B FED
,
ELE%tE FIELD
ELEMENT 0 J FIELD
ELEMENT E FIELD
FIELD INCREASES LEAD TO JNCRFASED FORCES BETWEEN ENCLOSURES
(b) Field distribution in insulated enclosures fOr a 'suppl y and 'return' circuit
tcti Field cancellation in a Continuous enCIOSure arrangement
FIG. 4.6 (coni'd)
Radial current flows due to current in an adjacent conductor
by the expression I = I o (1 — cos wt). Consider a
parallel adjacent conductor returning the same current. The magnetic field emitted therefrom would be B = B 0 (1 — cos wt). From Ampere's Law, the electromagnetic force between them is F = BI t, where f is the length of conductor, therefore, F
Bolo f' (1
—
cos cot) 2 .
Expansion of the expression (1 — cos 0)0 2 gives — 2cos cot + cos 20.)t), i.e., the force is composed of steady, power frequency and second-harmonic components. These three components of force are each reduced by a different shielding factor. For a detailed
explanation of these shielding factors, the reader is referred to the paper by Wilson and Mankoff [4]; however, the theoretical treatment of these effects is far from conclusive. Taking into account current decrement, there is a reduction with time of each of the electromagnetic force components, each component having a different decrement rate. The forces produced differ greatly, depending on whether the fault is three-phase or singlephase, the three-phase fault being more onerous. In principle, the short-circuit electromagnetic forces arise from the combined action of the various forces both between the phases and between the conductor and sheath of the same phase. However, as previously explained, for a continuous 1PB the external magnetic' fields and the resulting forces between conductors are 293
Generator main connections substantially reduced, compared with an unbonded system. Additionally, for a continuous 1PB, the forces between phases are much smaller than those which occur between each conductor and its own sheath. The magnetic field which exists inside the sheath on a continuous IPB system (as shown in Fig 4.6 (c)), produces a force between the conductor and the enclosure. The force on the enclosure results in the conductor being centralised along a magnetic neutral line. In a suitably designed IPB system, the neutral line is coincident with the axis of the enclosure, thereby irtually eliminating bending stresses caused by shortcircuit currents. The conductor supports are designed to allow for this slight movement as the conductor takes up its position on the neutral line. The force on the sheath is a repulsion or bursting force which can be represented as internal pressure on the sheath. The resultant mechanical stresses developed within the installation also depend upon the mechanical frequency response of the structure and will be exacerbated by any resonance that may exist. The foregoing text has attempted to show that the presence of the sheath in fact reduces forces and to give an awareness of the factors involved: it has not attempted a mathematical prediction of the forces which occur during a short-circuit. Whilst such force calculations may be attempted for straight sections of busbar, they are much more difficult for bends and tee-offs. At these positions the sheath currents vary around the periphery and there is not the benefit of complete mutual compensation of magnetic fields from the conductor and enclosure. Thus, immediately adjacent to bends, very high short-circuit forces exist which tend to straighten out the conductor. There are also higher stray fields which may heat up adjacent steelwork. The 1PB structural support system must therefore be strengthened at bends and other places where the configuration changes. Mathematical analysis of currents, fields and forces within an IPB system have been attempted, but a main connections design by calculation is not deemed acceptable by the CEGB, for no mathematical method is available that can be used with total confidence. It should be recognised that whilst during normal operating conditions the magnetic field outside the enclosure is practically nil; during fault conditions the field is the difference between the components on the conductor and enclosure which, since there are different ti me elements involved, is very difficult to determine. Consequentl.y, the adequacy of the design is ultimately demonstrated by testing, as discussed further in Section 8 of this chapter.
2.3 Voltage rise Consider the voltage rise of an electrically-discontinuous IPB enclosure under fault conditions. Since there is no current flow along the whole length of the sheath 294
Chapter 4 installation, large voltages build up across the breaks. It is, therefore, generally necessary to limit the distance between the breaks to a less than desirable length in order to keep these voltages to an acceptable level. With electrically-continuous enclosures, however, the voltage is dissipated in ER drop along the enclosure length as it is generated. Enclosure voltages are consequently held at completely harmless values, even during maximum fault conditions. A typical voltage induced per metre length of continuous enclosure is 3 mV per 1000 A of conductor current.
3 Designing an IPB system In designing an installation, the factors to be considered include materials, conductor and enclosure dimensions required for specified maximum temperature rises, mechanical strength and structural steelwork requirements. Up until now only naturally cooled systems have been assumed and the predominating factor determining the cross-sectional area and configuration of the conductor for the main connections of a naturally air-cooled busbar is the permissible temperature rise. A tubular conductor has a low skin effect ratio, described later in this section, which helps keep down the AC resistance and hence losses. An adequate crosssectional area must be provided so as to remain within temperature confines proven by experience and not exceeding the temperature limits specified in BS159, i.e., a maximum conductor temperature of 90 ° C. The largest full-load current in the CEGB at the time of writing is 20.1 kA, but this will obviously increase as larger machines are developed. The higher ambient temperatures overseas give rise to lower temperature margins for export designs. Selection of the most suitable material for IPB construction is generally straightforward, the choice being between copper and aluminium. At present an unusual situation exists, whereby copper and aluminium are similar in price (usually copper is much more expensive), but aluminium is still the cheaper overall. Copper has approximately three times the weight, but 60% of the resistivity of aluminium. Since aluminium is the poorer conductor, more material is required but, because of skin effect, there is a practical limit to the advantage gained by increasing material thickness. Consequently it is necessary to increase the diameter which has the advantage of increasing the surface area and improving heat dissipation. Aluminium, being much lighter in weight, is easier to handle than copper; this, together with the development of modern aluminium-welding techniques, makes fabrication in aluminium much cheaper than in copper. The starting point for the designer is therefore to determine the dimensions of the conductor and enclosure appropriate to the specified operating conditions. For the purpose of this exercise, assume the
Designing an IPB system normal cylindrical conductor and enclosure configuration. From experience, an initial conductor diameter thickness is selected. Ft is then necessary to check and the resultant heat generated in the conductor, which Ltiven by: W c = I 2 R, W,
(4.1)
heat generated per unit length, W/m
= rated RMS conductor current, A R L = AC resistance of the conductor appropriate to the temperature of the conductor and the supply frequency, Ci/rn R. has to take account of skin effect. When AC current is passed down a conductor, the current tends to concentrate on the outer surface. The higher the applied frequency, the thinner is the effective conducting band. The AC resistance R a , is higher than the DC resistance Rd: R ac /Rdc is termed the skin effect ratio, a full study of which was made by Dwight [5]. An extract of one of the curves produced by Dwight for a circular tube is shown in Fig 4.7. It is suitable for aluminum or copper conductors and may be used for all temperatures found in the operational range of the main connections. The DC resistance is relatively straightforward to calculate. At 20 ° C, for a large diameter conductor with a thin wall section, it may be closely approximated using the expression: Wm
Rdc
= resistivity of the material at 20 ° C, Om D = conductor mean diameter, m t = conductor wall thickness, m e
For a conductor operating at a temperature other than 20 ° C, the resistance becomes: Rd, 0 = Rcie20 [I + ot20 (0-20)] \\ here a 0
In establishing the working temperature, it is assumed that for a natural air-cooled system, almost all the losses (W„ + W e ) have to be dissipated by radiation and convection from the external surface of the enclosure. Clearly the heat that must be dissipated is that quantity which would cause the maximum permitted operating temperature to be exceeded. An approximate expression for natural convection from the outside surfaces of a busbar enclosure, indoors but not in a compartment, at sea level and normal pressure, based on Dwight et al NI is: 1,A/ c0n = 1360 1.25/Do.25
w/m 2
where W ean = loss dissipated by convection from the enclosure, W/m 2 = average temperature rise of the housing, ° C D = diameter of enclosure, m and the energy lost by radiation is given by the StefanBoltzmann expression:
(4.3)
= temperature resistance coefficient at 20 ° C = temperature, ° C
Having calculated the DC resistance and knowing the ratio t/D, the corresponding effective AC resistance can be determined from Fig 4.7 for the conductor dimension selected. From this, the loss per unit length is calculated, using Equation (4.1). Next, consider the heat generated in the enclosure due to the enclosure circulating currents. The loss in each phase per metre length is: W e = 1 R e watts
W e = 0,91 2 R
(4.2)
7rDt %A here
Where l e is the enclosure current, R e is the effective enclosure AC resistance per metre and is calculated from the DC resistance in a method similar to that above for the conductor. Development of a formula for calculating the enclosure current is complicated by several factors, including the impedance of the bonding bars, the skin effect and the proximity of structural steel or other conducting and magnetic material, as shown by Niemoller [6]. The reader is referred to the IEEE paper [7] for the calculation of IPB losses. Type testing has shown that it is not unreasonable to assume that the ratio of enclosure current to conductor current (I) to be about 0.95 for an electrically continuous IPB system, i.e.,
(4.4)
Wrad =
where Wrad
Tm To Ar
5.67 10
8
ke[rl, — rel] A r W/m 2
loss dissipated by radiation from enclosure, W/m 2 = coefficient of emissivity of the enclosure surface = average temperature of enclosure surface, K = ambient temperature, K = effective radiation surface per metre of enclosure length, m 2 = factor depending on position of phase as described below 295
Chapter 4
Generator main connections
Iii,I1TJJJ1IIIm
20
7111111111111 EINNI111111 11111111111 111111111MINAM MEM= NOME 1111111lAW AM 1111/11WANW A glMr,AMNI MI ,r,Preairro
1 7
1 6 IN EFFECT RATIO -
1 3
1 2
40
20
60
80
100
'11
I R0
1 20
140
160
180
200
10 1:3 0 m
Fic. 4.7 Skin effect ratio for rods and tubes
Since the radiation from the outer phases will differ from the centre phase, the following factors should be included [9]. 360 — 4a For the centre phase k — A,360 and for the outer phase k =
360 — 2a
Ar
360 where a = sin
-1
(R/S)
R = external enclosure diameter, m phasing spacing, m Total heat loss from the busbar system in W/m run can then be established from (W c ,„„ + W rad)7rD. 296
Factors not included in the equations which will affect heat dissipation both by convection and radiation from the enclosure are physical arrangements, neighbouring structures and surface finish. It must be borne in mind that hot spots can occur, particularly at the ends of busbar runs where connections are made to auxiliary plant. This occurs because of poor current sharing in unsymmetrical current-carrying connections, as will be discussed later, or from the concentration of circulating currents. Experience suggests that the conduction of heat from associated plant, namely the generator itself and the transformer bushings into the connections, should also be considered. Summarising, (a) the heat generated (W/m run) in the conductor and enclosure with
Forced cooling the dimensions initially selected from experience can be calculated, i.e., W e + W. Then,
(b) allowing for specified temperature rises of conductor above enclosure and of enclosure above ambient, the quantity of heat dissipated per metre length by the selected installation can be calculated, i.e., 7 ( Wcon + Wrad) r D
The values of (a) and (b) are compared and, if they are not close the dimensions are revised and the process repeated. In the CEGB, the temperatures specified at present are ° • Conductor maximum temperature 90 C. ° • Enclosure maximum temperature 65 C. ° • Internal air maximum temperature 70 C. ° • Ambient temperature 40 C.
Having established the dimensions of the IPB system from load current thermal conditions, the designer must then consider fault conditions. Generally speaking, for a main run of IPB, the busbars are so large for continuous current-carrying requirements that the thermal requirements for shortcircuit conditions are more than catered for. Howe‘er, for a unit transformer or other tee-off, the continuous current rating is small but the fault current rating is very high indeed. Here, the fault current specified may influence the busbar dimensions that are required because of its thermal effects, therefore requiring repeat calculations to determine temperature rises during fault. However, the major design concern arising from fault considerations is mechanical strength. The deigner must provide a suitable support arrangement for he conductor and enclosure to ensure that the final :,iructure is of adequate strength to withstand the forces ihat are exerted on the system during fault conditions. f he forces have been briefly explained in Section 2 Or this chapter. For the conductor, the designer is looking to provide sufficient support to: • Prevent deflection between supports due to forces between conductors and between conductor and enclosures during fault. • Prevent damage due to 'straightening out' forces sshich occur at bends during fault. • Prevent damage due to 'knife switch' forces at the tee-off positions, again due to the conductor attempting to straighten along the line of maximum fault current.
An adequate structural support is required for the enclosure to withstand the resultant static and dynamic loadings that the system will experience during fault. The present view of the CEGB is that there is no mathematical approach to solving these problems that can be used with confidence. The designer may from his own experience use simple force calculations as a starting point. Reference [10] is such a suitable starting point. Ultimately, however, before a design can be considered acceptable, a full set of short-circuit and earth fault type-test evidence is required to substantiate the design, as identified in Section 8 of this chapter. Finally, the stray magnetic fields surrounding the main connections, as already described, can give rise to inductive heating of adjacent steelwork. For an IPB system, there is unlikely to be any problem with systems carrying less than 8000 A. However, above this, care should be exercised. It is not only structural steelwork which may cause problems, but also piping and pipe hangers, gas and air ducts as well as stairs and handrails. Heating of such components could ignite adjacent flammable material, be a danger to personnel, cause structural stresses due to restrained expansion, and of course, incur additional running costs due to the losses. Analysis of this problem is most difficult and use is made of existing heat run tests. If the reader wishes to pursue the problem, an approach is described by Swerdlow and Buchta [II] and there are some guidelines regarding spacing of adjacent steelwork given in Section 7.18 of this chapter. Various methods are available to reduce the temperature rise of structural members, the use of shielding plates being favoured by the CEGB.
4 Forced cooling The optimum design of an IPB installation is determined by considering the capital cost, plus the cost of generating the associated losses. In order to satisfy the temperature balance requirements described in Section 3 of this chapter, naturally-cooled connection systems greater than 800 MVA, though practical, would require excessive space and consequently their cost would be high. For connections rated above 800 MVA, unless a much higher generator voltage is thought worthwhile, consideration must be given to forced cooling of the connections by some method. With reference to Fig 4.1, which shows a typical natural aircooled connection installation, it can be seen that the tee-off connectors from the main busbar carry a relatively low current, i.e., the high current flow is from the generator to the generator transformer. In considering the cross-sectional area of these components, it is clear that only the main run can justify forced cooling, the tee-off design being instead determined by the maximum fault current which could flow in it. Though it is unlikely that the use of forced 297
Generator main connections cooling below 8 kA would be economic, the limit for natural cooling, depending upon generator voltage, is reached at currents of 25-30 kA and, for currents in excess of this, the busbars are normally forcedcooled. Therefore, if forced cooling is to be considered, the heat balance approach taken in Section 3 of this chapter will have to include a calculation of the heat removed by forced cooling. Such calculations will depend very much on the design of the installation. The obvious choice of cooling medium is either air or water. In considering the economic case for forced cooling, the saving of material is offset by a possible increase in system losses, the additional cost of cooling equipment, routine inspection and maintenance of motors, fans, pumps, pipework, heat exchangers, etc. The value assigned to the losses/kW generated will obviously influence whether to force-cool the system if, in fact, temperature rise has not itself dictated its use. Once reliance is placed on forced cooling, any failure which might occur on the coolant plant would necessitate a consequential reduction in generated output, so it is desirable to aim for a high naturally-cooled current-carrying capacity, i.e., with the cooling plant out of commission. It is also necessary to specify the operating time at full-load current with the cooling plant shut down. The more common forced cooling systems are described below, though work is being carried out on the use of some of the newer insulating materials, for example, SF6 gas.
4.1 Forced air cooling A typical forced air system would comprise fans, heat exchangers, dampers and air filters arranged such that there is one set of equipment for each machine unit. Cooled air is blown from the heat exchanger, usually a finned water-cooled coil, down the busbar run between the enclosure and the conductor and returned to the heat exchanger, thereby forming a closed circuit. Such schemes are used extensively in the USA and, for a normal installation, air may enter the centre phase of the connection system, travel along it and return back through the outer two phases, sufficient air volume being used to ensure that the final air temperature does not exceed the maximum allowable touch-temperature of the enclosure. The cooling equipment may be located at any point along the connections system but the most economical position is midway between the generator and its transformer. Since the cooling air passes through the entire system, splitting the total cooling air volume in the centre phase and forcing it in opposite directions results in less overall system resistance, therefore requiring less fan power. The air must be cleaned and dried to reduce the risk of faults and all the associated equipment, including the fans, must be duplicated to ensure availability (2 x 100 07o or 3 x 50 01o). 298
Chapter 4 In addition, if the cooling air leaves one phase and enters another, then de-ionisation plant is required to prevent ionised gases produced by a system fault entering other phases, thereby extending its severity. Air has the obvious advantage of being cheap and plentiful but because it has a relatively low specific heat and density, large quantities are required to remove the heat and the fan requirement is proportional to the cube of the flow rate. This disadvantage can be overcome if liquid cooling of the conductor is considered. The rating for a forced air cooled installation with cooling plant shut down would probably be in the region of I hour and the naturally cooled rating would be approximately 60% of full load.
4.2 Liquid cooling It may be considered that the obvious choice is to extend the transformer cooling oil into the main connections conductor, as oil has a low specific heat and density compared with water. However, the fire risk associated with oil within the power station buildings is unacceptable. It is also considered unacceptable to risk the integrity of the transformer insulation by involving any other plant in the oil circuits — even delta boxes (see Section 5.4 of this chapter). Demineralised water has been used as the cooling medium in the generator stator for many years and the techniques have been well proven. It would therefore be possible to extend this system to include the generator main connections or, alternatively, to install a separate water cooling system.
4.3 Water cooling Since water has a better thermal conductivity and specific heat than air, the temperature rise of a main connections installation of this type can be more easily controlled by adjustment of the coolant flow than in an air cooled system. The material cross-sectional area provided in these circumstances is then based on consideration of the capitalised cost of the conductor losses (see Chapter 3, Section 2.1.5) against the capital cost of the conductor itself, together with the mechanical strength requirements for fault conditions. Clearly the water in the conductor is at the same potential as the conductor itself, so some form of potential dropping device is required between the conductor and remainder of the hydraulic circuit, which should be at earth potential. This device is a resistance column consisting of a long pliable connector of non-conducting material having a small cross-sectional area, thereby providing a high-resistance path to low currents. The cooling water then flows within a closedcycle cooling system with a heat exchanger, itself indirectly cooled by water. The cooling system may be incorporated in the stator cooling circuit, if the heat
System description oenerated in the connections system is small relative -o the heat removed from the stator windings.. ft will t then be found most convenient to connect the hydraulic cooling circuits in series. The conductor opcrating temperature should then be only slightly above the cooling water temperature. Joints between sections of conductor are welded, the elds, apart from requiring the necessary mechanical w ,irength, being watertight. Where conductors are connected to the plant, braided flexible connectors are used to allow for expansion and provide vibration immunity from that plant, the terminal palms themselves being within the connections, bridged by the water cooling circuit, the bridge being of non-conducting material. Heat conduction to the conductor helps keep down the temperature of the flexible connections. A water cooled system would have no short-time full-load rating and a naturally cooled rating in the event of loss of forced cooling, of approximately 20%. The major disadvantages of a water system, therefore, are the substantial reduction in unit output if cooling is lost and the danger of an earth fault developIna if a water leak occurs. The reliability of the water seals is therefore very important.
5 System description A schematic drawing of a typical main connections system is given in Fig 4.8.
NEUTRAL END
LINE END
GENERATOR
The generator windings are star-connected, the star point being formed outside the generator, so there are two generator terminals for each phase. The output of the generator is taken from the line end of the phase windings, the star point being formed at the neutral end of the windings. It is desirable, for ease of making connections to the generator, to have these two ends located as far apart as possible, their relative positions being dependent on the generator manufacturer's frame design. The generator transformer is wound in delta/star configuration, the LV side being the delta winding. This transformer may consist of one three-phase tank or three single-phase tanks. The delta connection of the transformer can either be formed below oil or, as is now more common, can be made part of the main connections system to maintain phase isolation. An oil delta is not nowadays favoured since it allows any contaminated oil due to a fault in one phase to circulate into the other phases. Connections are taken from the main busbar to the HV terminals of unit auxiliary transformers and the system voltage three-phase earthing transformer (if fitted), discussed in Section 11 of this chapter. This connection, known as a tee-off from the main busbar, again maintains phase isolation up to the bushings, the transformers themselves generally being housed in three-phase tanks. There is a requirement to monitor voltage conditions on the main connections system for various purposes,
IPO DELTA
GENERATOR CIRCUIT BREAKER (IF APPLICABLE)
m
X
GRID VOLTAGE
m
EARTH SWITCHES
GENERATOR TRANSFORMER VOLTAGE TRANSFORMER CUBICLE
STATOR NE TL E ,1",="!+NG RES SCR
r--
EEE :_ CC.A. - C.N OF PROTECTION CM
FIG.
SYSTEM EARTHING TRANSFORMER {IF APPLICABLE)
UNIT TRANSFORMER
4.8 Generator main connections — simplified schematic
299
Generator main connections including generator synchronising, tariff metering, instrumentation, automatic voltage regulation and protection schemes. There is also the requirement to monitor current conditions, for example, for protection purposes. The requirement to monitor voltage is met by the connection of voltage transformers (see Section 7.8 of this chapter) onto the main connections via a further tee-off similar to the auxiliary transformer teeoff described earlier. Up to four voltage transformers per phase may be required, mounted within cubicles which maintain the phase isolation of the system. Current transformers (see Section 7.9 of this chapter) are mounted in the main connections runs, in positions dependent upon the protection scheme adopted. Other equipment may be included in the main connections system, such as connections to generator excition plant, earthing devices and to the generator circuit-breaker. These will be discussed later. The various features of the main connections system are now described in greater detail.
5.1 Line end The position on the generator of the line terminals depends on the generator manufacturer but the two obvious locations are either above or below the machine. Both positions have advantages and disadvantages for the main connections system. In all cases, consideration should be given to generator rotor removal without the necessity to dismantle any of the main connections installation. Any support given to the connections should be independent of the machine to prevent the transmission of vibration. Where the main connections leave the generator from above, the overall height of the machine is obviously increased. This may increase the height of the turbine hall crane-rails, and hence the turbine hall itself, thereby creating a cost penalty. Also, connections above the machine and their support structures can, if incorrectly designed, suffer fatigue due to vibration excited by the generator. If, how ever, the line connections are below the generator, there are obvious obstructions which require to be negotiated, for example, the generator foundations, generator/turbine auxiliary equipment, access ways, etc. Clearance from such obstructions can dictate whether the busbars lie side-by-side or in trefoil configuration. Other practical issues to be resolved at the generator line-end terminals are heat dissipation due to confined space, access for stator cooling pipework, prevention of water ingress and spacing of the line terminals, which may be arranged on the generator in an in-line or trefoil configuration. Where space is restricted, it may be necessary to consider the use of specially designed sections of busbar having reduced conductor and sheath dimensions, a terminal box arrangement with phase segregation, use of other than circular cross-section busbars or a short water-cooled 300
Chapter 4 section (see Fig 4.9). In the case of a segregated terminal box the phase barriers should be of the same material as the box (probably aluminium) and earthed to ensure that there is an earth plane between phases which reduces the risk of phase to phase faults. Phase to earth faults produce fault current which is restricted by the neutral earthing equipment. However, there is always the possibility of an earth fault developing into a phase to phase fault which causes much greater damage; it is therefore preferable to use a phase isolated system if possible. Early design co-ordination at the interface connection onto the machine is necessary to solve the problems associated with terminal spacing and ensure that the specified impulse-withstand level can be achieved. To allow for possible hydrogen leakage through the generator terminals, a complete bushing-type seal should be provided in the main connections run to limit the volume into which hydrogen could possibly enter. This volume at the generator should then be suitably ventilated to ensure that approximately four air changes per hour can take place within the enclosure to reduce the risk of build-up of hydrogen in air, which could form an explosive mixture.
5.2 Neutral end The method of generator stator neutral earthing is described in Section 11 of this chapter. An example of stator neutral earthing is shown in Fig 4.10. Again, depending on the machine manufacturer, the generator neutrals can be situated on the top or the bottom of the generator. It is obviously more straightforward if they are positioned below, as all the stator neutral earthing equipment described can then be housed within a single module supported on independent steelwork adjacent to the neutral terminals. If the terminals are located on the top of the machine, while the star connection can be made easily, vibration may be excessive if the stator neutral earthing transformer is mounted on the machine frame or support and therefore it should be located away from the star bar. Vibration would certainly prevent the resistor being mounted on the machine. Either a cable connection would be required (which is undesirable as it is vulnerable to damage) or, alternatively, a short section of IPB could be used and the transformer located away from the star bar. Equipment installed on the top of the machine can raise the height of the turbine hall with a consequential cost penalty. Due consideration should be given to preventing ingress of water into the neutral end equipment, since ventilation must be provided for the resistor to dissipate the heat produced during an earth fault.
5.3 Tee-offs Tee-off connections are used to connect auxiliary transformers and voltage transformers to the generator
System description
Fic. 4.9 Specially designed busbar sections for use in space-restricted areas
voltage system. The power requirements of a voltage iransformer are minimal so for these tee-offs, but not others, a reduction in current-carrying capacity is acceptable, provided that a suitable fuse is mounted immediately adjacent to the tee-off connection to deal v.ith faults. CEGB uses a 10 A fuse at this position. Downstream of this fuse (a distance generally of the order of a few metres between the main and the VT cubicle), the tee-off need only be designed to be mechanically sound. To ensure that an adequately strong design is offered, the CEGB specify a continuous rating of 300 A for this section. Tee-off enclosures can be bonded into the main run or isolated and treated as a separate section of IPB,
the choice being made by the designer and fault tested as a system.
5.4 Delta connections The connection of the delta on recent stations, e.g., Littlebrook D and Heysham 2, is made by using airinsulated IPB and, since the current flow in each delta arm is less than the line current by a factor 1/../3, the dimensions can be reduced appropriately from that of the main run, though the system highest voltage is the same. To ensure that the correct phasor grouping of the transformer is achieved, correct phase sequence 301
Chapter 4
Generator main connections
M
GENERATOR TERMINAL PLATE
FLEXIBLE CONNECTION
STAR BAR 32kV
1
500V
NE,JTRAL ENCLOSURE
STATOR NEUTRAL EARTHING MODULE
FIG.
4.10 Stator neutral earthing
of the LV and HV phases for the installed transformer winding terminals is essential (see Chapter 3, Transformers).
5.5 Excitation busbars Some generator designs use rotating excitation equipment, whereas others use separately-located stationary equipment. In the latter, the electrical connection between the exciter equipment and the machine is an 1PB system similar to that of the generator voltage system, though obviously running at the much reduced design voltage of 3.6 kV and maximum continuous current rating of 5000 A (AC or DC) (1988), with consequential reduction in size. Typically, the installation ould comprise AC and DC connections forming a system as shown in Fig 4.11, with a normal operating voltage of below 650 V, connecting the main exciter, the exciter rectifier cubicle, the field suppression switch, and the generator slipring and brushgear enclosure.
5.6 Earth bar The earth bar system is quite complicated since all associated auxiliary equipment must be earthed in a manner such that no circulating-current paths can occur; a typical system is shown in Fig 4.12. For the purpose of its design, it is assumed that the neutral earthing equipment (see Section 11 of this chapter) has been shorted-out due to a coincident fault and that the earth fault current is unrestricted. The earth path must be rated to carry the maximum earth fault current from any part of the connections system where an earth fault could occur back to the generator. For 302
LOCATION OF PROTECTION C%
an installation which includes generator voltage switchgear, an additional earth is incorporated on the system to provide the earth when the switch is open. The earth path must be of low resistance to prevent a rise in potential on any part of the system (during a fault) above a level which could cause a danger to personnel. With the system operating normally, the CEGB specify this level as 55 V and, during fault conditions, 430 V is specified as the maximum rise of earth potential to comply with telecommunication directives within the UK. However, if faults can be cleared within 200 ms a voltage rise of 650 V is acceptable. If no earth path were provided, the return earth fault current would follow a random path (or paths) of low resistance back to the machine. These routes may be tortuous and not adequate to carry such large currents. The provision of a designed earthing system directs the flow of earth fault current along a predetermined route, thereby containing all earth fault currents within the main connections system. The earth path comprises an earth bar of adequate cross-sectional area connected to plant by flexible leads and held at the potential of the station earth network. Since the earth bar would provide the lowest resistance path to earth fault currents, the earth bar redirects the fault current away from the station earth system which, in any case, would not normally be rated for such large currents. The earth bar is not screened by an enclosure; when earth fault current flows, large external magnetic fields are produced, so it is usual to position the bar some distance from the main busbar installation to prevent excessive forces being produced. The earth bar has to negotiate many obstacles on its route, e.g., civil works, auxiliary plant, etc., so that it includes
System description
MAIN EXCITER
MAIN GENERATOR
CONNECT (DNS MAIN ExCITEw,' Ac CONNECTIONS
CCE X C ITA T ION CONNECTIONS
EXCITER RECTIFIER CUBICLE
FIELD SUPPRESSION SI.NITCH
F1(.. 4.11
NEUTRAL ENCLOSURE
Exciter busbar arrangement
GENERATOR FRAhviE
R
RA
TG RAENNSEF O RI R
ST ATrION LOP RTN
Li
JJ VT
VT
4
UNIT
TRANSFORMER
VT
MAIN CONNECTIONS EARTH BAR
FIG. 4.12
many
bends. It is essential that sound fixing is provided to prevent the force produced by the fault current from straightening out these bends.
System earthing
When testing a main connections design, it is usual to include the earth bar, thereby testing a complete system. 303
Chapter 4
Generator main connections
6 Setting out the specification Having described a typical main connections Installation in the previous sections, consideration is now given to the design specification of that system, assuming natural air cooling. Section 7 of this chapter ‘vill look at the component parts. The first consideration is the particular application — the environment, voltage and current-carrying requirements. As standard a design as possible should be specified, so that testing need not be necessarily repeated for each application. The parameters that must be specified are: • The maximum system voltage, frequency and power factor. • The output of the generator, and hence the line current. • The variation allowed on the above during abnormal conditions. • The fault contribution from the generator. • The fault contribution from the external grid network. In a tee-off busbar, there is a combined fault infeed from the generator and the external grid. This specifies the maximum fault level of the system for which the installation must be designed, including the earth bar. The maximum system voltage dictates the impulse level for which the system must be designed and the consequential clearances between the conductor and the enclosure. However, it should be remembered that the impulse and switching overvoltages entering from the HV side of the generator transformer are not transferred according to the winding ratio of the transformer but rather to the ratio of the capacitances of the HV and LV sides. Depending on the steepness of the incoming wave, the percentage overvoltage on the generator side may be higher than the HV side. This overvoltage may be reduced by the capacitance of the generator and the generator main connections. Economics and workability dictate the choice of material for the conductor and the enclosure; aluminium is the most probable, bearing in mind that the electrical resistance should be low but the inherent mechanical strength adequate to withstand the forces produced during fault. The phase configuration, i.e., flat in-line or trefoil, and probably the spacing, will be determined by obstructions on the proposed route. The number of bends should be kept to a minimum and those selected should be of a tested design. The enclosure insulation level from earth must be specified. This level must be high enough to allow for degradation caused by dust during the periods between cleaning. At present the CEGB specifies 3.6 kV. The temperature rises permitted during maximum continuous current flow are then specified which, for 304
CEGB installations, are as stated in Section 3 of this chapter.
7 Component parts of an 1PB system
7.1 Conductor and enclosures These items have been dealt with in detail in the preceding sections.
7.2 Equipment enclosures At interfaces with plant, for example a transformer, the physical enclosure of the conductor must include access for maintenance purposes but still insulate the enclosure system from the connected plant. Non-conducting bellows, discussed later in this chapter, connect the enclosure to, say, the transformer, the tank of which is earthed separately. This equipment enclosure may have viewing ports (see Section 7.12 of this chapter) in order to inspect the flexible connections making up the conductor interface, and an access cover to allow the application of a portable earth if necessary (see Section 12.2 of this chapter). The enclosure may be a bolted assembly, removable for maintenance purposes, and using bonding strips to ensure that all parts are earthed positively and that no reliance is put on the bolted construction for earthing. To prevent circulation currents occurring, larger access covers should be insulated from the rest of the enclosure, except for a single earth connection on each individual cover. For the same reason, hinges should be bridged, using
a flexible connector. Designs should offer the facility of taking a transformer out for maintenance, while allowing the main connections to be re-energised safely. This latter requirement may be achieved by the removal of links or a short section of conductor, and the fitting of caps over the busbar ends in a manner which maintains the insulation of the system.
7.3 Insulators 7.3.1 Post insulators
These support the conductor within the enclosure to maintain the air clearance needed for the highest system voltage. They are made either of epoxy resin or of porcelain; if porcelain, it must be thoroughly vitrified, so that the glaze is not depended upon for insulation. The strength of the insulators should be such that when they are supporting the maximum short-circuit loads, the factor of safety is not less than 2.5. The number of supporting insulators at each point and the spacing between them is confirmed by short-circuit testing. Typical arrangements are shown in Fig 4.13.
Stresses due to expansion and contraction in any • part of the insulator and its fixings must not lead to
Component parts of an IPB system
FIG.
4.13 Typical insulator support arrangements
h e development of defects. The fixings, which should be non-magnetic, should be such as to allow movement of the conductor when centralising forces occur during short-circuit. The post insulator is usually mounted on plate which bolts externally onto a flange fitted to the enclosure, as shown in Fig 4.14, thereby permitting easy removal of the insulator. t
7.3.2 Foot insulators (including enclosure supports)
between it and the enclosure to accommodate thermal expansion. Where supporting structures suffer excessive vibration, installations may require anti-vibration pads to be incorporated in the design, although the CEGB does not generally use them. The design of the connections mountings should be such that the natural frequency of any part of the busbar structure and its supporting metalwork does not lie between ± 30 07o of the frequency of the applied electro-magnetic force, i.e., static and dynamic loadings for the power frequency specified should be taken into consideration.
These are plate-type insulators which insulate the
support side of the enclosure from the structural steelwork. An insulation level of 3.6 kV is generally specified for this device, which allows for some dust build-up during the operation of the plant. The support structure itself should allow relative movement
T OF BUSBAR
NTLiCTOR
CONDUCTOR SUPPORT FOOT
POST INSULATOR
7.3.3 Disc bushings
Disc bushing seals are fitted at the end of busbar runs adjacent to plant housings to provide an airtight seal, thereby preventing hydrogen from the generator, or oil from the transformers, passing along the isolated phase-runs in the event of leakage. The isolated phaserun is then fed with conditioned air, as discussed later. A bushing seal must also be provided in the VT teeoff, allowing the on-load maintenance of the VTs without affecting the conditioning air system. Careful attention is given to the bushing profile to ensure that moisture, which would reduce the creepage path of the bushing, cannot be trapped in it. 7.3.4 Wall seals
INSULATOR BASE PLATE ASSEMBLY REMOVABLE
11(.. 4.14 A typical insulator support assembly
Wall seals are provided where the enclosure passes through a wall (see Fig 4.15). The individual enclosures are connected to the wall seal using the bellows arrangement described in the next section. A similar seal is fitted where the installation passes through a floor. Also, to prevent transformer noise causing annoyance in residential areas, the generator transformer may be fitted with a noise enclosure. A wall seal will then be required for the busbar to pass through that enclosure. 7.3.5 Bellows
The bellows maintain the insulation of the main connection enclosures from the connected plant (see Fig 305
Chapter 4
Generator main connections
laminae. Alternatively, aluminium bellows may be used. The bellows are usually of synthetic rubber, completely weatherproof and airtight and must withstand at least twice the design working pressure of the conditioning air system within the enclosure. When bellows are located outside buildings in direct sunlight, the material must be chosen to ensure that degradation does not Occur.
7.4 Conductor and enclosure expansion joints Allowance for the expansion and contraction of the conductor (Fig 4.17) and enclosure (Fig 4.18) is provided on the longer busbar runs. This typically comprises a 'cage' arrangement, where the expansion gap is bridged by aluminium laminae. The connection must have adequate current-carrying capacity and correct current-sharing among the laminae is ensured by using a symmetrical array of laminae. Ho, 4.15 An example of a wall seal
7.5 Flexible connectors
4,16). They allow relative movement due to expansion and vibration, and cater, to a limited extent, for any installation misfit due to the worst combination of allowable tolerances. When bellows are installed on a length of busbar at, for example, a conductor expansion point, they must be bridged using flexible aluminium
Flexible connectors can be laminae or braid, the choice depending on the type of relative movement of the parts being connected. When removed, they provide isolation of plant. The significant difference between them is that laminae only allow relative movement in two dimensions, whereas braid gives full three-dimensional movement.
ENCLOSURE
BELLOWS ASSEMBLY
DETAIL SHOWING T BANDS EACH SIDE OF BELLOWS
GRUBSCREW STEEL BANDS TENSIONED AND FASTENED
Si mfn GAP !NOMINAL}
I 1
CROSS SECTION OF BELLOWS SHOWING GAP IN NORMAL POSITION
FR,. 4.16 A bellows assembly
306
Component parts of an IPB system
FIG. 4.17 Main conductor expansion joint
ALUMINIUM LAMINATE
-z&
LAMINATE ASSEMBLIES OMITTED FOR CLARITY
FIG. 4.18 Enclosure expansion joint — typical arrangement
7,5.1 Flexible laminae connectors
hese are constructed from thin strips of aluminium laid one above the other, with aluminium palms welded Ott each end (Fig 4.19). Suitable holes in the palm 3110w the connector to be bolted to the conductor palm. Their applications are limited to sections of main runs (for example, to allow the insertion of
CTs) at expansion joints, connections to generator voltage switchgear, and earth connections to some items of plant. 7.5.2 Braided flexible connectors
These are made up of tinned-copper braid or braids (Fig 4.20) with ferrules fitted at each end which are 307
Chapter 4
Generator main connections
ALUMkNIUM LAMINAE
WELD
SOLID ALUMINIUM TERMINAL PALM
Fin. 4.19 Construction of a flexible laminae connector
LAYERS {THREE IN THIS CASE)
CRIMPED SIDE FACE
FERRULE TUBE THICKNESS
THICKNESS OF COMPRESSED FERRULE ---
11%.
BRAID
FERRULE TUBE UNCOMPRESSED
WIDTH OF COMPRESSED FERRULE
CONTACT SURFACE (FACE) COMPRESSED FERRULE FASTENER HOLES
Fin. 4.20 Construction of a braided flexible connector
drilled to allow a bolted connection onto the terminal palms of external plant. It is essential that the ferrules are crimped onto the braid, since sweated assemblies have been found to suffer from mechanical creep problems, with failure resulting after a period of time. Clearly, whilst the braids overcome the problem of relative movement of component parts of the system, they introduced a dissimilar metal interface when connected to the aluminium conductor palm. 308
It has been found preferable to remove tinning from the ferrule at the joint interface surface. Methods of overcoming problems associated with dissimilar metals are discussed later. Careful selection of the braids is necessary to ensure that there is adequate current-carrying capacity and that they are capable of operating continuously at the maximum specified temperature. Consideration should be given to:
Component parts of an IPB system
•
The length of braid compared with the gap, to ensure that there is adequate flexibility (ideally there should be 25-35 mm free play).
The number, size and position of the fixing holes • on the crimped ferrule (which affects the clamping pressure on the joint and hence its current-carrying capability). •
The ambient air temperature within the enclosure.
7.6 Painting The outside of the conductors and the inside of the enclosures are normally painted with matt black heatresistant paint to improve heat transfer.
7.7 Conditioned air Bolted inspection covers, portable earth access covers and the insulator base fixing-plates are provided with Easkets, and the ends of busbar runs incorporate a disc bushing. These measures prevent the leakage of moist or polluted air into the enclosure. It is usual to pressurise the enclosure so that leakage is outwards io atmosphere. The leakage rates are approximately Ocro by volume of the busbar enclosure per hour. This airflow, though quite small, purges any ionised oases which may have accumulated inside the enclosure and prevents condensation forming, particularly during periods of shutdown. The cooling effect of this air is not taken into account in the design of the busbar and therefore failure of the associated equipment does not necessitate shutdown of the unit. All the main connections within the confines of the bushing seals are fed with dry conditioned air at 12.5 mbar(gauge). To prevent condensation, the design is based on a dewpoint of - 25 ° C. A typical system comprises one air compressor and its associated receiver and drying equipment per unit. Alternatively, if available, air supplies can be obtained from the Station Instrument Air System. Either source is acceptable, though sizing and rating problems can occur with instrument air sources. It is usually preferable to provide an independent compressor. Some air is fed around the disc bushings to vent to atmosphere after passing through the equipment housings.
nearest preferred ratio to the present generator voltage with accuracy maintained for 0-100 07o rated output. The primary sides of the VTs are earthed at one end to a common earth, which is then connected to the generator stator earth. They are fed from the voltage transformer tee-off busbar via fuses rated to discriminate against the fuse located at the tee-off from the main busbar. In the secondary circuits, any earth connections are made to the Station earth, as that is the earth which is used in instrumentation circuits. Some manufacturers have traditionally provided tertiary windings on their voltage transformers connected in delta and used to prevent the occurrence of neutral inversion and voltage transformer ferro-resonance. The delta winding is closed solidly or through a loading resistor, depending on the X/R ratio needed to prevent ferro-resonance. Neutral inversion is the displacement of the neutral due to abnormal system conditions, such as open-circuits in one or more phases of systems possessing inductance and capacitance. Ferro-resonance can occur when the magnitude of the inductance of the VT compared to the capacitance of the circuit to which it is connected is equal and opposite. When not required, the tertiary windings are left open-circuited with one open-end earthed; this is usual with neutral earthing methods now used. The reader is referred to Chapter 3 (Transformers) and Chapter 11 (Protection), for a more detailed discussion of these issues and the problems they cause.
7.9 Current transformers Current transformers (CTs) are located in various parts of the installation, depending upon the protection scheme employed. Typically, for the scheme shown in Fig 4.1, CTs would be installed in the following locations (shown in Fig 4.8). At the neutral end of the stator winding, between
the terminal plate and the star-bar, for the following purposes: • Tariff metering. • Efficiency testing. • Unit instrumentation and turbine-generator automatic control input signals.
7.8 Voltage transformers
• Low forward power protection.
Voltage transformers (VTs) are mounted within a cubicle (see Section 7.16 of this chapter) which is designed so that the transformer can be safely removed for maintenance without requiring access to live parts, should that be required during operation. A typical VT weighs in the region of 100 kg. It is generally a single-phase cast-resin transformer connected in a star arrangement with a ratio of 22 kV/110 V, the
• Negative phase sequence and loss of excitation protection. • Generator differential protection. Within the generator neutral earthing module on the secondary side of the neutral earthing transformer for stator earth fault protection (see Fig 4.10).
309
Generator main connections At the unit transformer for • Generator differential protection. • Unit transformer differential protection. On the 11V bushing of the generator transformer for generator differential protection. The design of the CTs must be such that they do not reduce the electrical impulse-withstand level or the power frequency withstand level of the installation. The CTs positioned in the main connections busbar are of the 'slipover' type, mounted within a housing, for ease of erection. They include an earthed screen to shield the secondary winding from the electric field of the conductor, thereby allowing the secondary insulation level to be a nominal 2 kV. This assembly is held at earth potential by connecting the CT core-shield assembly to an independent earth cable at one point only, to prevent any circulating current paths. All secondary cabling should be glanded on an insulated glandplate, thereby maintaining the 3.6 kV insulation level of the enclosure. Adequate support and bracing of the CTs is required as a typical assembly is heavy; a neutral CT assembly may weigh 600 kg and a line CT assembly 350 kg. Sufficient ventilation must be provided to ensure that the heat produced in the windings does not cause unacceptable temperature rises. Any forces exerted on the CTs during fault conditions will be li mited to those attempting to centralise them around the neutral line of the enclosure. These are not significant if the CTs are mounted concentrically. There will be little, if any, axial force exerted on the CTs and this is easily contained by the mountings. The generator has an impulse-withstand level of 85 kV, consequently a similar figure can be allowed for the neutral-end equipment. CTs should be clearly labelled with details of their duty and their orientation within the system must be identified to ensure the correct polarity of secondary signals.
7.10 Environmental conditions For design purposes, the relative humidity should be taken as 100% and any equipment mounted out-ofdoors should be completely weatherproof and capable of withstanding inclement weather conditions, including wind and snow loading, and solar heating. The entire installation should be drip proof, dust proof and vermin proof, with an enclosure rating to at least 11)45 of BS5490.
7.11 Portable earth access covers The philosophy of portable earthing is discussed in Section 11 of this chapter. The mechanism by which 310
Chapter 4 it is applied is covered here. The design of the access covers must allow reinstatement of the air conditioning system when portable earths are applied to prevent condensation and dampness forming within the main connections system during periods of prolonged outages. The access cover to the enclosure must allow good access to the conductor and earthing device within the enclosure, but be securely bolted and hinged when not in use, The earthing connection onto the conductor is made by a clamp and is applied using an insulated pole. A flexible cable then connects this via another clamp onto the main connections earth system. The access cover must also allow the application of a voltage testing device. CEGB safety rules require the cover to be lockable.
7.12 Viewing ports Viewing ports, comprising clear glass or Perspex viewing windows, are provided in the enclosure at positions where there is a need to check the condition of flexible connectors and other equipment regularly. These also permit the use of infra-red heat measuring devices for checking the temperature of the connectors.
7.13 Connection of the conductor to plant As detailed earlier in Section 7.5.2 of this chapter, braided flexible connectors are used to continue the conducting path to the connected plant. At the generator, a 'candelabra' assembly (see Fig 4.21) has been developed which forms a circular terminal arrangement fitted to the machine terminals. Braids then bridge the gap between the main connections conductor and the generator terminals forming, in effect, a short cylinder that assists equal current-sharing among the braids. Care must be taken in the design to ensure that there is adequate clearance from stator water cooling pipework. Connections onto the generator transformer, which may be either a three-phase tank or three single-phase tanks, are by braided flexible connectors onto six terminal bushings. A typical arrangement in isolated phase busbar is shown in Fig 4.22. To give a good current distribution, the connections onto the bushings should be arranged in as near circular configuration as possible, typically eight palms arranged in an octagonal formation (see Fig 4.23). A single palm connection would not give good current distribution and should be avoided. However, since the generator transformer connections carry phase current rather than line current, there is no need for the elaborate candelabra arrangement used at the generator. Connections to auxiliary transformers, e.g., the unit transformer, are simpler than the generator transformer since the load currents are much lower. The temperature rise due to losses in the connections system must be reduced in areas where significant
Component parts of an IPB system
GENERATOR TERMINAL
BRAIDED FLEXIBLE CONNECTOR ONLY TWO CONNECTORS SHOWN FOR CLARITY
FlG. 4.21 Generator terminal 'candelabra' connection
heat may be conducted from plant, for example, at the generator and the generator transformer via its bushing. The specifications for these items permit higher temperatures than are permitted for generator main connections. Access to terminals should be as easy as possible, with the removal of a minimum of enclosure components to gain access to the terminations. 7.14
Joints in the conductor
Ahhoue.h apparently simple, joints have given serious Problems in the past, due to the unequal current-sharing in braids and poor pointing procedures. One cause sometimes aggravates the other and leads to the even-
tual failure of the joint, often with catastrophic results. A joint (which really consists of many joints in parallel) can be so badly burnt-out that the original cause of the fault is impossible to determine. Consequently, extensive experimental work on joints has been performed by the CEGB to establish the most suitable joint surface preparation assembly and fixing procedures. There are several influencing factors to consider when making a joint: • The material of the mating surfaces to be joined. • The preparation of the mating surfaces. • The bolt size. • The bolt material. 311
Chapter 4
Generator main connections
NELJ
-
RAL
•RATP HOL,IS IN C, S.
AIR DELTA mAIN PHASE
—
3 X SINGLE - PHASE GENERATOR TRANSFORMER
NV BUSHING REMOVABLE GENERATOR TRANSFORMER TERMINAL HOUSING FLEXIBLE CONNECTIONS AND LV BUSHING
1-7
-7
GENERATOR TRANSFORMER
_
V T CUBICLES
•
UNIT TRANSFORMER TERMINAL HOUSING
Flo. 4.22 Air delta arrangement in isolated phase busbars
• The size of spreading washer to give necessary clamping load. • The necessary torque. • The method of locking the nut. The materials making up the joint are normally either aluminium or copper; the joints are therefore copper to copper, aluminium to aluminium or copper to aluminium, in order of increasing difficulty in making the joint. It is recommended in the CEGB that where surfaces are coated or plated this should be removed at the interface by linishing, so that one of these three joint interfaces is created. Without going into the science of jointing, the most satisfactory method will be described. The jointing surfaces are first cleaned a wire brush, a separate wire brush being used for each material. A liberal coating of petroleum jelly is then applied to prevent further oxidation. High-tensile steel bolts, washers and nuts are then torqued-up and locked, the number of bolts depending on the size of the ferrule being bolted. Recommended sizes of these components are shown in Table 4.1. 312
TABLE 4,1 Recommended dimensions for bolts and washers used in jointing Washer Bolt size Inside dia
Outside dia
Thickness
Min
mm
mm
Torque Nm
M6
6.4
14
2
7
M8
8.4
21
2.2
20
M 10
10.5
24
2.4
35
M 12
12.8
28
3.0
50
M16
16.8
34
3,4
90
7.15 On-load temperature measurement As can be appreciated, temperature measurement of an IPB system is not easy, but it is necessary during commissioning to ensure that the design requirements have been met, and during operation to ensure that there has been no degradation of joints, flexible connectors, etc. During commissioning, there are various
Component parts of an IP2 system
EIGHT TRANSFORMER DISC BUSHING
ACOUSTIC ENCLOSURE EXPANSION BELLOWS
ACCESS COVER_j
EXPANSION BELLOWS
-
ACCESS COVER
BONDING STRAP
TRANSFORMER BUSHING
'
Fic. 4.23 Generator transformer connections
'stick-on' tapes available to record the maximum temperature attained at a spot. They have the obvious disadvantage that they can only be read after the system has been de-energised but they are a useful way of doing a temperature survey. Temperature-sensitive paints are also available which change colour at a set temperature. For both these methods, it is essential to ensure that, once the sensor has been 'triggered', it remains stable until an opportunity to check it is available. Thermocouples and contact thermometers also exist, but they are generally only of use on the star-bar because of the high voltages involved. An alternative method is an infra-red camera, which obN iously requires line-of-sight vision to the spot to be measured. Painting the surface of the joint can improve the efficiency of emission of infra-red. Since magnetic fields can influence an infra-red camera, caution must be exercised when using it.
7.16 VT cubicles Each phase may require up to five VTs arranged in isolated phase compartments. When isolating a VT, it is usual to break the primary side before the secondary side, so that isolating contacts compatible with the secondary voltage can be used. Each VT is separately protected by a primary fuse, typically 3 A, which discriminates with the 10 A fuse fitted at the tee-off, already described. The VT secondary wiring, suitably fused, is wired to a combined CT and VT secondary marshalling cubicle and then into its associated protection or instrumentation scheme. When the VT is isolated, before access can be gained to it, earths must be applied by the VT isolating mechanism to both sides of the 3 A fuse, and the primary and the secondary terminals of the transformer. To ensure that this procedure is followed, the VT cubicle door is interlocked.
Because of the difficulty of temperature measurement, indirect methods of monitoring can be considered. Checks of joint resistance, using a micro-ohm meter, can be made during plant shutdown, and all joints checked for obvious signs of discoloration due to high temperature.
7.17 Access platforms
If viewing ports are provided, both the infra-red camera and visual checks for discoloration are possible. Hot spots only occur at jointed areas; the general busbar temperature is not a problem, provided that the busbars have been correctly designed.
avoidably located at awkward places; access platforms are therefore necessary to facilitate quick inspection of joints and connection of portable earthing equipment. Sufficient room must be available for an operator to manoeuvre voltage sensing probes, earth application
Since the main connections route is complicated by proximity to other plant, some access covers are un-
313
Generator main connections poles, etc. Care must be taken to ensure that ladders and handrails do not bridge insulated joints electrically at plant interfaces and thus render them ineffective. Also, such structures in the vicinity of the connections are designed so that they are not heated b ■ stray magnetic fields during continuous operation of the plant. The continuity of any current-conducting path in the steelwork should be interrupted by the inclusion of insulating pads, bushes and washers, etc. Attention should be given to the need to sectionalise or insulate cladding or screens.
7.18 Structural steelwork Structural steelwork running parallel to main connections enclosures must be spaced at least 300 mm distant. Steelwork running at right angles to main connections enclosures must be spaced at least 150 mm distant. The supporting structure for the whole of the main connections, including the tee-off connections, is designed to give a rigid structure for the static and dynamic loads imposed with a typical safety factor of 1.5. Supports must be completely independent of the equipment to which the busbars are connected and separate from main building steelwork. They are floor-mounted and designed to prevent heating of the structure by magnetic leakage fields.
7.19 Neutral earthing equipment This equipment has developed in the manner described in Section 11 of this chapter and, for a 660 MW generator, typically comprises a solid insulation (SNAW) 462 kVA cast-resin transformer with a suitably-sized load resistor and anticondensation heater mounted within a free-standing module, one per unit. The transformer is normally unenergised, so particular attention must be given to ensuring that the complete encapsulation performed under vacuum is free from voids, cracks and other defects, and accurate location of the winding is essential. The resistor is likely to be of the metallic type and have a value which limits the earth fault current to 10-15 A in each neutral. It will be air cooled, non-deteriorating, non-corrodible and fireproof, non-inductive and capable of carrying the earth fault current for five minutes without mechanical damage: the total resulting temperature rise should not exceed 200 ° C.
7.20 Site installation Clearly it is advantageous to do as much factory fabrication as possible, subject to transportation limits. Equipment housings and sections including bends require more complicated fabrication techniques and are best done at the works, leaving the relatively easy welding of straight joints to be done on site. The sec314
Chapter 4 tions are transported complete, i.e., they include conductor, enclosure, insulators and all fittings.
7.21 Quality assurance Notwithstanding the quality checks required for each individual component, careful final assembly and welding of the busbar sections is most important. Welding must be in accordance with a specified standard, e.g., 13S3571 Part 1 for metal arc welding or BS3019 Part 1 for tungsten arc welding (both inert gas), and all welds must be clearly identified in the design, including their type, weld process, weld preparation, with samples of each weld type made available for examination. Welds can be grouped as electrical circuit welds or structural/ mechanical welds and detailed welding procedures are prepared. Testing of welds by radiography and dyepenetrant techniques is carried out on a percentage of all welds produced, with clear acceptance levels agreed before work starts.
8 Testing This section covers tests for: • Component parts of the main connections installation. • Manufacture of a test piece to ensure adequate design. • Testing on site. • Type tests. • Routine tests. • Sample tests.
8.1 Tests on component parts 8.1.1 Insulators and bushings At the time of writing, these components are made of an epoxy material. Type tests are carried out on samples of complete insulators representative of each type used in the installation; they will already have passed the specified Routine tests. Each insulator type needs a different jig in order to subject it to realistic testing. The necessary corrections for temperature, barometric pressure and humidity are applied. Typical type tests are: • Lightning-impulse voltage withstand This is the standard 1.2/50 As impulse test with the test conditions given in BS3297 Part 1 1974 or BS223 1985 as appropriate, the test value being that for the highest system voltage of the installation.
• Dry power frequency withstand
To BS3297 at the appropriate test value for one minute.
Testing • Wet power frequency withstand
To BS3297 at the
appropriate test value for one minute. Carried out in accordance BS4828, the partial discharge being measured in terms of apparent charge; the level should not
• Partial discharge test
e\ceed 50 pi,:acoulombs. •
Cantilever mechanical owe-test This is applied to a complete insulator secured by its normal means of ji \ jog, with the load applied at right angles to the asis of the insulator. This test would not be applied
• Ultimate cantilever-load sample test
Finally, a unit should be loaded up in the cantilever mode until failure occurs. For this sample test, failure should not occur below 80N of the failure load obtained from the Type testing.
8.1.2 Busbar material
to a disc bushing. The following Routine tests should be carried out on all individual insulators and bushings: • Visual examination. • Electrical routine test
mately 50° -1() of the specified puncture voltage applied across the unit. This voltage is then increased graduall ■, to 1.3 times the actual dry flashover voltage of the unit without causing puncture.
Checks are made to ensure that the material is to specification and that different material types are clearly identified, so that the incorrect material or thickness cannot be inadvertently used in any part of the installation.
A 1-minute withstand test at
the appropriate voltage. A cantilever test at 70 07o of the failing load of the insulator in this mode.
• Afechanical routine test
In addition to these Type and Routine tests, the following Sample tests should be performed; the method of selection is discussed in BS3297 Part 1, 1974: This involves checking that the dimensions are in accordance with the relevant drawings, with due regard for tolerances and other details which may affect interchangeability.
• Verification of dimensions
Several cycles of i mmersion in hot and cold water, the sample being held at each temperature for one hour to ensure (hat a uniform temperature has been attained. The difference in hot and cold temperatures should not be less than 70 ° C. This test would be followed by a routine electrical test to ensure that no degradation of the insulator has occurred.
• Temperature cycle sample test
8.1.3 Transformers The various VTs and CTs throughout the system require Type and Routine tests, as described in Chapter 3. 8.1.4 Loading resistors The neutral earthing system loading-resistor must be tested in accordance with BS587: 1957, as follows: Type testing
• High voltage. • Ohmic value of resistor. • Temperature rise. Routine testing
• High voltage. • Ohmic value of resistor.
• Oscillatory-load sample test
This simulates mechanical shocks onto the main connection installation caused by, for example, operation of a circuitbreaker. The number of oscillations selected is left to the judgement of the engineer specifying the installation (of the order of four million), but is not applicable to disc bushings.
• Tension sample test
Each sample insulator is subjected to 70 410 of its ultimate tensile failure load for one minute without failure to it or its fixings. It is not applicable to disc bushings.
• Torsional sample test
A torsional load is applied to each threaded insert or stud of an insulator or bushing to demonstrate that no permanent distortion or loosening of fittings occurs. For thread sizes up to M12, a load of 50 Nm is used.
• Puncture sample test
For this, the insulator is i mmersed in switchgear oil and a voltage of approxi-
8.1.5 Capacitors Capacitors may be installed in the main connections for the reasons explained in Section 10 of this chapter. They should be tested in accordance with BSI650. 8.1.6 Switchgear and earthing switches Testing requirements for switchgear are discussed in Chapter 5. Type and routine testing of earthing switches is in accordance with BS5253, the test arrangement simulating the service condition as far as practical, i.e., the switches should be mounted in their service enclosures, together with a section of busbar. The short-circuit test is made on a three-phase group of switches, but all other tests may be performed single-phase. Control and electrical interlocking circuits, if applicable, should be tested for correct operation. 315
Generator main connections
Chapter 4
8.1.7 Compressed air system
All compressors, pipework, valves and ancillary apparatus are tested to appropriate standards, i.e., the pressure of their associated safety valves, with air receivers being pressure tested to one and a half times their safety valve operation pressure.
8.2 Tests on representative sections of IPB It has been explained earlier that calculation of the forces that exist upon a main connections installation during short-circuit is very difficult and at the time of writing there is no reliable calculation method available. Any computational method later developed will require validation by testing. Consequently the CEGB's normal practice is to test the capability of a main connections design by subjecting it to the worst fault currents which might occur in service. There are limited facilities worldwide where tests of this kind can be carried out, and such testing is very expensive. It may be advantageous for the manufacturer to offer a main connections installation of higher current rating than is necessary simply in order to use a tested design, thereby making repeat tests unnecessary. It is normal to offer two test pieces; a section of main and tee-off busbar, including the tee-off itself,
and the delta section. The former requires representation of all three phases and the earth bar whereas for the latter a 'go and return' section plus earth bar suffices. An example of a test piece comprising aluminium busbar in an aluminium enclosure representative of a unit transformer tee-off connection is shown in Fig 4.24. Consideration should be given to incorporating additional equipment into the test piece, for example CT chambers, expansion joints, flexible connections, etc. The following design aspects of the test piece should be considered. in addition to the selected test piece, it is advisable to add a short interface section where connections are made to the incoming unscreened section of the test station busbar. This reduces the end effects of non-representative connections on the test piece. The connection to the test station supply is by flexible connections, as used in normal service. The short-circuit is by means of a shorting bar of construction generally similar to part of the main connections installation. It is connected to the test piece by joints similar to a normal tee-off but strengthened, typically by welded webs, in order to withstand the high knife-switch forces in this area, those forces being higher than those in practice at a right-angle bend. In a single-phase-to-earth fault, connection to the test piece is in a section of earth bar returning to the test
FIG. 4.24 Test piece for generator main connections
316
Testing station connections by unscreened conductor, this being representative of a normal earth bar arrangement in a pical design. Laminated flexible sections should be provided at each end of the screened conductor and the conductor held down in the manner proposed in the earth bar design. Bonding bars should be incorporated in the tot piece at the test supply end, though short-circuit bar enclosure will provide the bonding [be b et ween individual phase enclosures at the remote cnd of the tes• piece. It is recommended that the following measurements are recorded: • Input The applied current (and voltages) are recorded on UV oscillographs. It is advisable to take additional current measurements using Rogowskicoil type current transducers in various parts of the test piece, these being particularly useful for diagnostic purposes should some failure occur. (If any CTs are fitted in the test piece, they should have their secondary windings shorted unless some measurement of their output is required.)
piezoelectric force transducers should be positioned to measure load on the earth bar. If a correlation is being made between the test results and predictions by calculation, as many transducers as possible should be applied to the earth bar to give greater confidence in the calculation method.
• Force
•
Voltage rise The voltage rise in various parts of the test piece should be measured relative to one point on the test piece.
• Temperature
Maximum-indicating temperature devices of the stick-on type should be liberally applied to the test piece in order to record the maximum temperature reached. These should be examined after the one-second test (see Section 7.15 of this chapter) to ensure that the final conductor temperature does not exceed specification. Clearly, initial temperature prior to short-circuit must be recorded to determine temperature rise. The thermal shortcircuit capacity of the main busbar is far in excess of the actual values due to the high continuous current and large conductor and enclosure crosssections. For the unit transformer tee-off, the temperature rise has less margin due to its relatively smaller cross-section.
The values of fault conditions are the sum of the contributions from the generator side and the generator transformer side of the system. The design values should be applied throughout the system, including the associated earth bar system, to ensure a high integrity. For a 660 MW installation, the test levels quoted would be as follows: (a) Equivalent RMS short-circuit three-phase 200 kA fault current for I second (b) Calculated first loop peak of (a)
630 kA
(c) RMS short-circuit single-phase equivalent to each fault current for 1 second (i.e., this represents the heating effect equivalent to that fault current which actually flows, taking into account current decrement)
168 kA
(d) Calculated first loop peak of (c)
435 kA
The earth fault values assume that the generator neutral earthing transformer primary is short-circuited. (a) and (c) are thermal tests, whereas the peak tests (b) and (d) are mechanical. Representative parts of the design are also tested to demonstrate: • Lightning impulse-voltage withstand, using the standard 1.2/50 its impulse, i.e., that there is adequate air clearance between conductor and enclosure. At present generator voltages, a test level of 170 kV peak full-wave is used, applicable to a system highest voltage of 36 kV. • Power frequency one-minute dry withstand corresponding to the above figure, in this case 70 kV RMS at 50 Hz. Due to the less-onerous service conditions, the tests on exciter systems (see Section 5.5 of this chapter) can be confined to: • Power frequency dry withstand, 10 kV RMS for one minute at 50 Hz. • Full wave lightning-impulse withstand, 5 positive and 5 negative discharges, at 40 kV. • A heat run of 5000 A RMS for 8 hours, including adequate instrumentation to survey the whole system.
8.3 Test levels The fault conditions normally quoted in a specification
8.4 Tests at site
are synthetic insofar as the actual fault currents that flow on a given power station installation cannot be predicted precisely. The test values are therefore derived from real plant parameters, assuming that all [he variables combine at their worst. The test philosophy is based on the presumption that any real fault vh ill be less severe than the test condition.
The complete installation, including compressed air pipework if fitted, for a 660 MW Generator would be subjected to either a dry one-minute power frequency voltage-withstand test at 68 kV RMS or a dry fifteen-minute DC voltage test at a test level of 66 kV DC. The insulation resistance is measured before and after this HV test. The connections to the generator 317
Generator main connections and transformer windings are disconnected during the test. In addition to the above, a heat run is carried out on the complete installation, using the generator as the po\1/4 er source to ensure that the main connections design is satisfactory for the rated overload current and temperature condition. This test is performed by short-cireuitine the main connections on the grid side of the generator transformer, closing the HV earthing s\\ itches in the grid connection to form a three-phase short-circuit and adjusting the generator voltage to eke the maximum continuous rated current of the connections. A liberal number of temperatures should be recorded and the installation run for sufficient time to become thermally stable. Finally, the enclosure installation should be subject to an insulation-to-earth test appropriate to a 3.6 kV insulation level. Similar tests are performed on the exciter connection, though at a reduced level.
9 Experience of testing In the event of an unrestricted fault at or in the unit transformer, the main connection system cannot prevent damage at the point of the fault. It is therefore considered that a specification for the main connections should ensure that: • They are not the source of any faults. • The connections will not compound a fault occur ring outside outside the main connections terminal points. • Their design must be such as to allow a return to operation with the minimum possible refurbishment. The test results of a main connections design are therefore analysed with the above criteria in mind. The short-circuit testing of designs undertaken by the CEGB has not been without incident and has shown that the desiener cannot rely fully on calculations. This is true both of the thermal and the mechanical shortcircuit tests. The distortion of the test sections caused by mechanical forces has been considerable. In addition, the rise in potential of enclosures and earth bars has been higher than predicted. Experience has shown that as many measurements as possible, of all the parameters, should be taken so that all the results of the test can be fully interpreted. An adequate supply of measuring devices is also essential, since some can be damaged during the test. Since test laboratory time is expensive, detailed preparation work is essential to ensure a trouble-free test session. This requires a complete understanding of the requirements among contractors, laboratory staff and customer. It is essential to ensure that the test connections from the test station are arranged such that no unrepresentativ e stress is put on the test piece due to their presence. 318
Chapter 4 The results of all short-circuit tests that have been performed to date by the CEGB allow some general comments to be made concerning the areas of the design which are most critical. Faults in the past have generally been associated with small-section conductors, sharp changes of direction in small-section conductors, welds in small-section conductors and end effects at bonding bars. Generally, the main conductor cross-section required for continuous maximum rating is such that it has ample short-circuit withstand capability. The same is true of the main enclosure except, for example, w here extra local loading is placed upon it by poorly supported bonding bars. Nevertheless, it is still essential to include a section of main busbar in the test piece in order to steady the unit transformer tee-off and other small or complex section conductors, e.g., in line laminae, bolted joints, earth bar fittings, etc. Details of some - typical problems revealed in testing are: • Enclosure bonding bars, if not sufficiently robust, will be distorted at the test piece ends during the mechanical test. Bonding bar movement can pass the stress down to the enclosure support feet, causing them to distort. • The additional forces that exist due to end effects are revealed by general relative movement and distortion of the conductors at the test piece ends, though elsewhere the conductor and enclosure must remain straight and undistorted. The forces in this end area can damage laminae or braided flexible connectors. • Inadequate earth bar cross-section and insufficient holding down points can allow the earth bar to distort severely: this is probably one of the most common problems revealed by testing. This demonstrates the effect of lack of shielding since the earth bar is not provided with a sheath. It also illustrates that a system of this mass, when subjected to forces produced by the fault current, will suffer distortion and possible damage whilst absorbing the energy present. The conductor is a large, very rigid structure supported by a strong insulator system in a braced enclosure itself supported on strong insulated feet. This assembly has little flexibility and a large mass (very high inertia). The earth bar, whilst supported at many points and of large cross-section, is relatively less massive as a system and in the event of reaction between it and the conductor system it is the earth bar that suffers most damage. • Because of the centralising force exerted on the conductor by the enclosure, damage can result to the feet supporting the conductor by spreading or cracking, and the design must cater for this force. • Testing has shown that during short-circuit conditions, diametrically opposite laminaes or braids
Generator voltage switchgear will be attracted together when forming part of the conductor and repelled when part of the enclosure. This can cause movement of the conductor and d mage to the support insulator feet, or indeed the a
insulator itself. •
The forces produced during the mechanical test prOs ide a comprehensive check of the adequacy of the welding specification.
• During th.‘ testing it is common for extensive arcing and smoke to be produced, generally caused by paint in joints of the test piece frame burning out due to circulating current. If such arcing is to be eliminated, sound electrical joints in the frame are required. Some other significant factors have arisen concerning instrumentation of short-circuit tests. The principal object of the tests is to short-circuit proof test a busbar specimen. The instrumentation pro% i ded is intended to provide supplementary information for comparative records as well as data that might help in the ensuing fault analysis. Taking the instrumentation normally applied in turn: -
(a) Voltage measurement Measurement of enclosure voltages does prove useful, but care should be taken when interpreting the results. The intention is to measure the voltage drop along the enclosure when fault current flows in the conductor. The actual enclosure currents are the sum of many complex and interacting phenomena. For example, the principal enclosure current flows on the inner surface but currents induced by other conductors flow on the outer surface. The current flow in the enclosures is not homogenous, but is subject both to concentrations and eddies. As a result, placing a set of potential measuring points along the outside of a relatively short test piece of complex geometry will not yield a smooth potential gradient along the test piece. However, experience has demonstrated that enclosure monitoring points can show when arcs or conducting metal touch the enclosure. Additionally, providing that the correct measuring method is chosen, useful information can be derived concerning the earth bar and the voltage drops along it. (b) Strain gauges Strain gauges are very sensitive to electrical interference and, furthermore, unless great care is taken when positioning them, they can be affected by thermal expansion of the test piece. Converting the results obtained into meaningful loading figures is unreliable because of the difficulty of defining exactly how the loadings are produced. (c) Temperature The stick-on maximum temperature indicating devices are a perfectly adequate means of recording temperatures during these tests.
(d) Film record The basic concept of a film record is sound and such a record should be specified. Some shortcomings have been highlighted in recent tests which should be dealt with. The designer's assumption at the outset of testing is that no major problems will be encountered. Thus filming is carried out in a fairly standard fashion, using a frame speed in the region of 5000 frames/s at the instant of the fault. If a fault occurs in which the camera sees an electrical arc, then the film record from this point onwards is virtually useless. On other tests where an arcing fault has been intentionally provoked, filming has been performed through a high sensitivity neutral filter. The illumination of the arc is sufficient to penetrate this filter and give a rough outline of the surrounding equipment but, prior to the arc, the fil m is totally blank and unexposed. One possible solution, on a test where it is not known whether arcing will occur, is to run both normal and filtered cameras simultaneously, although this is wasteful of film should a fault not occur. It is also complicated and expensive in terms of the initial equipment to be provided. Another potential solution currently being investigated, centres around a product marketed for military use. A chemically-treated plastic, transparent under normal illumination, becomes almost opaque when subject to intense ultra-violet radiation. The time taken to change from clear to opaque is very short indeed, and a filter of this material applied to the lens of the camera might offer a cheap and ready insurance against unexpected arcing faults with the possibility of recording evidence during the arc.
10 Generator voltage switchgear Only a brief mention of this equipment is made here: the actual switchgear is described in Chapter 5 and the factors to be considered regarding its use are discussed in Chapter 1. However, if such equipment is incorporated in the main connections installation, this affects the layout of the busbar and calls for additional equipment to be installed, e.g., pneumatic equipment, cooling equipment and, possibly, system capacitors. The switchgear is located in the horizontal run of busbar and an area, preferably enclosed, must be provided to house it. Due to the physical size of the switchgear, increased centres between phases will be required in that area. The switchgear comprises an independent 'interrupting device' per phase, thereby maintaining complete phase isolation throughout the system. Consideration must be given to the foundation requirements for mounting the switchgear. The switchgear itself may be either water or air cooled, the option being selected after consideration of the continuous current-carrying capacity and therefore 319
Generator main connections the quantity of heat to be extracted, air cooling having obvious limitations. To minimise transmission of shock to the main busbars due to the operation of the switchgear, flexible connections are made between the switch and busbar, normally using aluminium laminae. Caution should be exercised if aluminium laminae are used, as this may reduce electrical clearances to an unacceptable degree if the switchgear was designed to be connected by copper laminae. Since a continuous circuit for circulating current within the main connection enclosure is required, loop connections to the body of the switchgear must be provided, the most suitable being aluminium laminae. Another significant factor affecting the main connections is whether the switchgear is fault-rated or is lower-rated as is a switch disconnector; the implications of this decision are discussed fully in Chapter 1 of this volume. However, depending on the characteristics of the switchgear selected, and in particular the value of the transient recovery voltage (TRV), capacitors may have to be added to the system, fitted between the conductor and the earth, to cater for the satisfactory operation of the generator switchgear under all operating conditions. The most suitable position for these capacitors is generally in a specially designed compartment within a VT cubicle, a three-phase bank of singlephase capacitors being connected between phase and earth. These are used to decrease the steepness of the switching or fault clearance voltage wavefront in order not to exceed the maximum allowable voltage stress on the insulation of the equipment. They reduce the rate-of-rise of recovery voltage at the interruption of short-circuits and load currents. Capacitors can also reduce overvoltages caused by single-phase faults on the LV side of the generator transformer. The capacitors themselves comply with BS1650 or equivalent specification, and are preferably of the steel-tank oilfilled type, having insulation and impulse voltage capabilities equivalent to those specified for the remainder of the main connections installation. The capacitors should incorporate discharge resistors to ensure that they are safely discharged to earth potential, following the shut down and isolation of the plant. When the capacitors are installed in the VT cubicle and the teeoff cubicle is fed through fuses (Section 5.3 of this chapter), then those fuses must be capable of handling the capacitor inrush current without failure. The design of the generator stator neutral earthing is described in Section 11 of this chapter. If generator switchgear is installed, main connections system between the switchgear and the generator transformer is unearthed when that switchgear is open. To cater for this, a system neutral earthing transformer must be installed between the switch and the transformer which will form a neutral point on the LV side of the generator transformer. This neutral earthing transformer has an interstar primary with its neutral point earthed via a transformer and resistor, these last two 320
Chapter 4 components being similar to those used for the generator stator neutral earthing, already described. Consideration must be given to the additional synchronising requirements when generator switchgear is employed. The normal measuring VTs, already described, are installed between the switchgear and the generator (see Fig 4.8). To monitor the 'system' side of the switchgear either a supply can be taken from the system neutral earthing transformer, by incorporating a tertiary winding within it, or an additional tee-off and VT provided instead. If system capacitOrs are needed, the latter is the better solution and the VT cubicle would then house both the additional synchronising VTs and the system capacitors. The methods of earthing for maintenance purposes are different for installations with and without generator switchgear.
11 Earthing The methods of earthing the main connections, namely stator neutral earthing and systems neutral earthing, have already been discussed, together with the earthing requirements for the enclosure system and for connected equipment, for example, transformer tanks. This section briefly explains the philosophy of earthing the generator and its connections. Prior to 1950, the normally established earthing practice for the neutral of a main generator connected to the system by transformers, was to use a voltage transformer, the secondary of which generally operated an alarm in preference to tripping the generator. A number of serious breakdowns in the early 1950s caused this practice to be abandoned. Instead, the neutral was earthed via a low resistance, namely a liquid earthing resistor. The resistance was typically 22 ohms for 30 MW and 60 MW generators operating at 11.8 kV, so that the maximum line-to-earth current would be about 300 A. The time rating of the resistor was 30 s. This method continued until the 1960s when, instead, earthing was effected by a low resistance connected to the LV winding of a distribution-type matching transformer, the HV winding of which was connected in the neutral lead (see Fig 4.10). This has worked satisfactorily and costs no more than earthing through a liquid earthing resistor. The high effective resistance to earth fault current limits the damage at the point of fault and there is the advantage that the resistor can be designed for low voltage with attendant robustness and reliability. The surge-reflection characteristics of this system have been found to be satisfactory. This scheme has the additional advantage that, because the maximum earth fault current is very low, in the order of 10-15 A, a sensitive setting of the protection relay, as shown in Fig 4.8, can be used in the unit protection scheme. Clearly, the fault current flows in the transformer primary winding, so the current-limiting resistor on the secondary side of the matching transformer
Earthing for maintenance purposes carries a higher current. During normal conditions with stator currents balanced, no current flows in the the neutral earthing transformer. initially, when this scheme was developed, the transormer and resistor were situated some distance away from the star point, sometimes outside the turbine . ansformer was oil filled. This necesh a ll, since the :t ,icated the use of a long length of cable, an earth fault %hich could only be detected during outage times. on ■ (Heads such a fault on this cable would, during an unrelated earth fault on the system, cause unrestricted earth fault current to flow. Consequently, a cast-resin tspe transformer was developed which is located adjaent to the star-bar together with its loading resistor, thereby increasing the integrity of the system by having short a connection to the star-bar as possible. as See also Section 10 of this chapter for details of .s stem neutral earthing when a generator switch is installed.
12 Earthing for maintenance purposes Before any maintenance work can be performed on a inain connections installation, the system must be eflei:f ively isolated by lockable means, and fully earthed. The methods used and the extent to which this is achieved depend on the Safety Rules of the operating At the time of writing, the CEGB uses a National Code of Practice for earthing high voltage apparatus which (simply put) calls for a 'Primary earth' to be applied within the isolated zone on which work is to be performed. This Primary earth must be of adequate cross-sectional area to discharge safely any fault current which may flow as the result of inadvertent energisalion. A circuit-breaker or a specially provided earth ■ Ifc.h or fixed earthing device must be used to make die first Primary earth connection. After application of this earth, the system then has a number of 'portable drain earths' added in accordance with an agreed 'Earthinv schedule' in positions such that, wherever work is to be carried out, the person performing the maintenance ‘A ork can see at all times that the portable drain earth is in position. The CEGB requires that a visible drain earth must be positioned within 10 m of the place of ork.
If generator switchgear is installed, the Primary earth
\k
itch must be located between the generator and the
generator switchgear. This earth then covers the section iii \shin it is fitted and also the remainder of the installation when the generator switchgear is closed. Therefore earthing procedures and sequences are different, depending on whether a generator switch is installed. 12.1
Primary earth
For a 660 MW installation without generator voltage
\kitchgear, it is considered that inadvertent re-ener-
gisation via the HV breaker in the substation is not credible due to the fact that it would be open and locked, as would the HV isolator, and the HV earth switches would be closed and locked. Any back-feed is then limited to: Unit auxiliary system
7 kA for 2 s
Residual magnetism at barring speed 1 kA continuous Residual magnetism at full speed
1 kA continuous
Full excitation at full speed
25 kA for 2 s
It is therefore deemed adequate that, for installations without generator voltage switchgear, the primary earth should be rated at 25 kA for 2 s. For installations with generator voltage switchgear, the section between the switch and the generator could be re-energised, since the switch is the point of isolation. Here, the Primary earth is applied by fully-rated motorised earth switches, complying with B55253, on the basis of one per phase for each generator unit. For a 660 MW generator installation, the follow ing minimum earth switch specification would be expected for a terminal voltage of 23.5 kV, 50 Hz. • i mpulse voltage withstand • Power frequency voltage withstand to earth • Continuous rated current • Rated short time current • Permissible duration of short-circuit • Rated peak current • Operating time • Rated short-circuit making current at rated voltage
170 kV peak 75 kV RMS 1000 A 160 kA 1s 440 kA peak 10 s 750 A peak
A typical earth switch arrangement is shown in Fig 4.25, one switch would be installed in each phase. The switch is mounted integrally with the main connections enclosure and penetrates to the conductor via a drive housing. The actual earth connection is made by a motor-driven lead-screw system operating a drum-type contact. A position indicator must be provided on the outside of the switch: a window in the busbar enclosure allows the position of the contact to be checked visually. It is usual to provide a handle for manual operation of the earthing switch, should that be necessary.
12.2 Portable drain earths These devices are applied after the Primary earth, as explained earlier in this section, and are rated to handle the maximum fault current. For a 660 MW generator 321
Generator main connections
Chapter 4
DRIVE MOTOR
FIG. 4.25 Single-phase earth switch
operating at 23.5 kV, the portable earthing equipment is rated at 17.5 kA for 2 s or, alternatively, 23.5 kA for one second. The portable earth is applied to the conductor after gaining access to it via a portable earth access cover.
A typical method of application is the fitting of a clamping device on the portable earth connection to a 'ball' fitted permanently to the conductor, the component parts being shown in Fig 4.26. The earthing clamp is applied to the ball, using an HV insulated pole of approved design. The pole is about two metres long so that the person applying the earth is never in any danger if, for some extremely unlikely reason, the equipment were alive. Similar devices are used to apply earths to substation equipment but a longer pole, typically four metres long, is used because of the higher voltages in those areas. Design of the clamping devices must be such that it is not possible to apply an earth with a two-metre pole, when a four-metre pole should be used. After application of the clamp onto the conductor, the portable earth access cover should be closed. At the other end of the portable earthing cable, another clamp is fitted, suitable for connection to the system main earth bar. For this purpose, secondary earth bar loops from the main earth bar run are provided adjacent to each portable earth access point, though the main earth bar run must be continuous and independent of such loops. Typical points to which it should be possible to connect portable drain earths are: • Generator transformer LV bushings. • Unit transformer MV bushings.
EARTH END CLAMP - CONDUCTOR EARTH BALL ICHAIN DOTTED)
OPERATING POLE
OPERATING POLE DETAIL
Pio. 4.26 Portable earthing device
322
Future trends
• •
System earthing transformer HV bushings.
14 Interlocking
Transformer side of unit transformer tee-off CTs.
Operational and maintenance interlocking schemes are discussed in detail in Chapter 1 but the designer of the main connections should be aware of the possible requirements for such schemes. The method of interlocking may be electrical on circuit-breakers and earth switches, but may be of the mechanical key-interlock type on other equipment. If minimal interlocking is used, then very strict administrative controls are required to ensure that the operator cannot gain access to live equipment and that a safe sequence of events has to be performed before access can be achieved.
Unit transformer tee-off.
•
Both sides of generator switchgear.
•
• VT cubicle tee-off. • VT cubicle side of tee-off fuse. • Generator terminals. capacitor terminals and tanks. • S ■ sieril Portable earthing equipment must obviously be examined regularly to ensure that it is undamaged and the results of such examinations must be recorded. It must also be examined immediately before use by the person responsible for the application of such earths. Careful recording of the number of portable earths applied and of their locations is essential to ensure that all are removed prior to re-energisation of the ,tem. This can be performed either by a mechanical interlock method (which can become very involved and time consuming on extensive systems), or by strict ,
administrative controls. The locations of some of the portable earth access eo‘ ers may be several metres above ground. Access platforms are provided, the design of which takes into account the difficulty of applying the portable earth clamp. Careful consideration must be given to avoiding induced circulating current in this steelwork.
13 Protection It is not intended to explain the protection systems employed to cover the main connections; these are fully described in Chapter 11. However, the designer of the main connections installation must be fully tis‘ are of the requirements for protection devices, such as current transformers, within the equipment and their accommodation within the design. He must also be aware of the operation time of the protection and design his equipment to carry fault current safely for that period. Present figures are quoted in Section 8.3 of this chapter. The design of accommodation must take into account ease of assembly, access for testing and ease of \itliciraval if a device becomes faulty. During cornmissionin2 and reinstatement of the main connections, primary and secondary injection tests must be performed to check the protection schemes. Also, consideration should be given to incorporating a primary loop through a CT for primary injection purposes +■ hen that CT is located in an inaccessible position, tor example, in a transformer bushing. Marshalling cubicles accommodating interposing current transformers and terminals for secondary wiring +% ill be required.
15 Future trends 660 MW generators are now the standard size used by the CEGB, though the industry is considering an increase from that figure for both fossil-fired and nuclear (PWR) stations. There are two possible future steps in the short term: the choice will probably depend on the type of steam raising plant. If the PWR concept is pursued, it may be decided to drive only one generator from each reactor, thereby requiring a turbine-generator rated at about 1300 MW. Future coal-fired plant may incorporate turbinegenerators rated at about 900 MW. Whichever option is selected, a move to some form of forced-cooling of generator main connections will be required, with a probable increase in voltage and higher line current; in this way, large dimensional increases can be avoided. A forced-air cooled system is the more likely since this would be a relatively simple extension of current designs. It may become possible, if adequate research work is performed, to increase the operating temperature of main connections. If so, it is. likely that silver plating will be required to avoid oxidation. Since the cost of testing main connections designs is so high, some development work would be desirable to reduce testing costs. This could involve either calculation methods or small-scale comparisons. In the former, a design would be completely modelled and the forces due to short-circuit calculated. Some physical testing would initially be required to validate the calculation method. As an alternative, it may be possible to model the installation or a representative part of it and to fault-test at higher than normal frequency. This reduces the size of the test piece required and consequently the cost. It also means that the test could be performed in smaller test stations rather than having to use the very limited facilities available for fullscale testing. Clearly IPB systems will continue to be required and the basic technology of this subject will apply for the foreseeable future. Only a rapid improvement in superconductivity techniques would cause a dramatic rethink of the materials and conditions used in the main. connections installations of tomorrow. 323
Generator main connections
16 References 1
f 1
Carter, F. W.: Note on losses in cable sheaths: Proceedings of Cambridge Philosophical Society No. 24, pp 65-73: 1927 Dwight, H. B.; Theory for proximity effects in wires, thin tubes and sheaths: AIEE Trans 42: 1923 Skeats, W. F. and Swerdlow, N.: Minimising the magnetic field surrounding isolated phase bus by electrically-continuous enclosures: A1EE Trans. No 62: 1962 Wilson, W. R. and Mankoff, L. L.: Short circuit forces in isolated phase buses: AIEE Trans: 1954 Dwight, H. B.: Electrical coils and conductors: McGraw Hill; 1945
324
Chapter 4 Niemoller, A. B.: Isolated phase bus enclosure currents: Trans. I EEE; August 1968 I EEE: Guide for calculating losses in isolated phase bus: IEEE Paper 298: June 1969 Dwight, H. B., Andrews, G. W. and Tileston Jnr, W.: Temperature rise of busbars: General Electric Review: May 1940 Albright, R. H., Conasla, A., Bates, A. C. and Owens, J. B.; Isolated phase metal-enclosed conductors for large electric generators Ashdown, K. T. and Swerdlow, N.: Cantilever-loaded insulators for isolated phase bus: AIEE Paper: April 1954 Swerdlow, N. and Buchta, M. A.: Practical solutions of inductive heating problems resulting from high current buses: Trans. AIEE 1960
CHAPTER 5
Switchgear and controlgear 1 General requirements Auxiliaries power systems — voltages and fault levels 1.1 1.2 Switchgear performance 1.3 Operational requirements 1.4 Control 1.5 Environment 2 Types of switchgear 2.1 Descriptions 2.2 Testing and certification 2.2.1 General 2.2.2 Certification 2.2.3 Type tests 3 Generator voltage switchgear 3.1 Required performance 3.2 Design and construction 3.2.1 General 3.2.2 Control 3.2.3 Cooling 3.2.4 Operating air plant 3.2.5 Phase-reversal disconnectors for pumped-storage schemes 3.2.6 Earthing switches 4 3.3 kV and 11 kV switchgear — circuit-breaker equipment 4.1 Required performance 4.1.1 Rated voltage 4.1.2 Frequency and number of phases 4.1.3 Rated insulation level 4.1.4 Rated short-time withstand current of main and earthing circuits 4.1.5 Rated peak withstand current of main and earthing circuits 4_1.6 Rated normal current 4_1.7 Rated short-circuit breaking current (of circuitbreakers} 4.1.8 First-pole-to-clear factor 4.1.9 Rated short-circuit making current 4.1.10 Rated duration of short-circuit 4 1.11 Rated operating sequence 4.2 Design and construction 4.2.1 General 4.2.2 Enclosures 4.2.3 Withdrawal/disconnection 4.2.4 Electrical interlocks 4.2.5 Coded-key devices 4.2.6 Identification of conducting parts 4.2.7 Earthing of structures 4_2.8 Circuit and busbar earthing 4.2.9 Auxiliary switches 4 2_10 Cabling arrangements 4.2.11 Voltage transformers 4_212 Current transformers 4.2.13 Control/selector switches 4.2.14 Switchboard/circuit identification 4.2.15 Indicating instruments 4.2.16 Test devices 4.2.17 Circuit-breakers 4.2.18 Circuit-breaker operating mechanisms
5 3.3 kV switchgear — fused equipment 5.1 Required performance 5.1.1 Rated voltage 5.1.2 Frequency and number of phases 5.1.3 Rated insulation level 5.1.4 Rated short-time current 5.1.5 Rated normal current 5.1.6 Rated breaking current of switching devices 5.1.7 First pole-to-clear factor: 1:5 5.1.8 Rated short-circuit making current 5.1.9 Rated duration of short-circuit 5.1.10 Rated operating sequence 5.1.11 Co-ordination of switching device with fuse protection 5.2 Design and construction 5.2.1 General 5.2.2 Duty of switching device and circuit earthing facilities 5.2.3 Switching devices 5.2.4 Switching device operating mechanisms 5.2.5 Main circuit fuselinks 6 Low voltage switchgear, controlgear and fusegear 6.1 Required performance 6.1.1 Short-circuit withstand strength of busbar systems 6.1.2 Capability required of main circuit making/breaking devices 6.2 Design and construction 6.2.1 General 6.2.2 Enclosures 6.2.3 Cabling arrangements 6.2.4 Electrical clearances and creepage distances 6.2.5 Busbar systems 6.2.6 Earthing of structures 6.2.7 Mechanical interlocks 6.2.8 Coded-key devices 6.2.9 Protective systems components 6.2.10 Current transformers 6.2.11 Ammeters and voltmeters 6.2.12 Control switches 6.2.13 Fuses 6.2.14 Circuit-breaker equipments 6.2.15 Contactor controlgear 6.2.16 Fusegear 6.2.17 Specialised switchboards/units 7 Fuses 7.1 Introduction 7.2 Definitions 7.3 Required performance 8 DC swItchgear 8.1 General 8.2 System conditions 8.2.1 Short-circuit withstand strength of busbar systems 8.2.2 Current making! breaking and short-circuit capability of main circuit switching devices 9 Construction site electrical supplies equipment 9.1 General 9.2 Portable substations 9.3 Portable distribution units (415/240 V) 9.4 Portable distribution units (110 VI
325
Chapter 5
Switchgear and controlgear 10.5 Vacuum switchgear 10.6 SF6 switchgear
1 0 Future trends in development and application 10.1
General 1 0,2 Oil-break switchgear 10.3 Air-break switchgear 1 0.4 Air-blast switchgear
1 General requirements 1.1 Auxiliaries power systems — voltages and fault levels The philosophy of the design of the systems of power supply to auxiliaries plant is dealt with in Chapter 1. This chapter deals with the operational facilities provided by, and the performance required of, the switchgear and controlgear used in those systems, and also with the switchgear used in schemes in which the main generators are switched at generator voltage. The design features necessary to meet these objectives in CEGB power stations are described. The presentation is intended to assist the engineer concerned with the application and operation of switchgear and controlgear rather than for the information of the specialist designer. In consequence, technical detail available from text books and such sources as 13ritish and International Standards is included only as necessary to illustrate a particular aspect properly. The terms and definitions used in this chapter are, in general, in accordance with the British Standard Glossary of Electrotechnical, Power, Telecommunication, Electronics, Lighting and Colour Terms — BS4727: Part 2: Terms Particular to Power Engineering — Group 06: switchgear and controlgear terminology (including fuse terminology). The terms and definitions are in close agreement with those of Publication 277 of the International Electrotechnical Commission, where there are corresponding terms and definitions in that Publication. Switchgear and controlgear are defined as follows: Switchgear and contra/gear A general term covering s witching devices and their combination with associated control, measuring, protective and regulating equipment, and also assemblies of such devices and equipment with associated interconnections, accessories, enclosures and supporting structures.
11 Bibliography 11.1 British Standards (BSI 11.2 Electricity supply industry IESI) Standards 11.3 Other relevant documents
connection with generation, transmission, distribution and conversion of electric power. Controlgear A general term covering switching devices and their combination with associated control, measuring, protective and regulating equipment, and also assemblies of such devices and equipment with associated interconnections, accessories, enclosures and supporting structures, intended in principle for the control of electric power consuming equipment. Except where necessary to avoid ambiguity, only the generic term switchgear, is used henceforth. By the early to mid 1950s, the design of the auxiliaries power systems in power stations in the United Kingdom had become established at the dual voltages of 415 V and 3.3 kV, with short-circuit levels of up to 43.3 kA (31 MVA) and 26.3 kA (150 MVA) respectively. However, the demand on the systems consequent upon the rapid increase in the rating of main generating plant and, in consequence, of its auxiliaries, thereafter necessitated the introduction of a higher voltage — 11 kV — having, initially, a short-circuit level of up to 26.3 kA (500 MVA), but progressing to the present value of 39.4 kA (750 MVA). Until the introduction of a third voltage, and with the aim of holding auxiliaries to two voltage levels, switchgear having a short-circuit capacity of 43.8 kA (250 MVA) at 3.3 kV was installed in some instances. However this expedient was soon abandoned in favour of the substitution of 6.6 kV, an innovation that was also short-lived as, yet again, auxiliaries power requirements were seen to be increasing beyond the capability of 6.6 kV. Thus, currently, and probably for the foreseeable future, the major power stations in the United Kingdom have 'three-tier' auxiliaries power systems, i.e., systems operating at 415 V, 3.3 kV and 11 kV. Additionally, there are services operating at lower voltages, e.g., 240 V AC, 110 V and 220 V DC.
Switchgear performance Traditionally, the calculated prospective current likely to flow under three-phase fault conditions in auxiliaries power systems necessitates (for the purpose of determining the short-circuit performance required of circuit-breakers) equipment capable of interrupting a current waveform featuring a transient DC compo-
1.2
Switchgear A general term covering switching deices and their combination with associated control, measuring, protective and regulating equipment, and also assemblies of such devices and equipment with associated interconnections, accessories, enclosures and supporting structures, intended in principle for use in 326
General requirements 070 at the instant of separation of the nent of up to 50 circuit-breaker contacts, together with an ability to 'make' a current of up to 2.55 times the steady state (symmetrical) RMS value. However, in installations feat urine g.as-turbine generators connected directly into ii kV voltage level, the influence of such mat he chines tc:wether \vith that of the connected motor load n, under short-circuit, produce in a phase at maxica asymmetry-, a waveform having a first major MUM loop peak of he order of three times the steady state R \IS value together with a relatively slow rate of decay of the DC component. The likelihood of the occurrence of this condition is governed by the point on the system at which the fault occurs, and also on the running mode of the auxiliaries at the time. In tact, the waveform of the short-circuit output current of a generator in a phase at maximum asymmetry may be so displaced relative to zero that it does not pass through zero for many cycles after fault inception. Figures 5.1 and 5.2 illustrate a typical current ‘‘aN,eform and circuit for a short-circuit at the bus-
bars of an 11 kV switchboard. It is thus necessary to evaluate the waveforms likely to appear on a system to ensure that the making current and asymmetrical breaking current capability of the switchgear is not exceeded. It is not sufficient to assess the fault clearance capability required of the switchgear solely on the basis of the symmetrical, i.e., steady state, value of the system short-circuit current.
1.3 Operational requirements The function of the auxiliaries power system switchgear is the distribution and control of electrical energy to station auxiliary plant. Depending upon the station operating regime and the duty of the plant controlled, some circuits are switched frequently, whilst others may remain on or off-load for long periods. Intermittent operation, as opposed to base-load operation of the generating plant, increases dramatically the switching frequency imposed upon many items of switchgear — particularly those controlling motor drives. Transformer circuits, on the other hand, suffer much less in this respect. Unless the nature of the drive calls for variable speed control, or a form of reduced voltage starting, all AC motors are switched direct-on-line regardless of size. Thus the normal operational switching duty of the switchgear may be described as: • The making and in certain circumstances the breaking of motor starting current, which may be up to six times full-load current and more in some low voltage circuits, i.e., 415 V. • The breaking of overload current. • The breaking of circuit normal full-load current.
Fr (r. 5.i Typical current waveform for a short-circuit at the busbars of an II kV switchboard t\ainple illustrated shows maximum asymmetry in he red phase.
AUEMARY GENERATOR
B uSEA RS
3 310., TRANSFORMER
5.2 Schematic of the short-circuit represented in Fig 5.1 showing direction of fault currents
• The making and breaking of transformer magnetising current — the avoidance of the generation of high overvoltage being of particular importance in this duty. Of no less importance is the protective role of the switchgear. Accordingly it must be capable of making, carrying until the operation of protection, and interrupting the maximum prospective current which may flow in the event of short-circuit anywhere on the system. Besides satisfying the switching and protective roles, the switchgear must be equipped with all facilities necessary to permit its operation in accordance with legislation in the United Kingdom (UK), and also the Safety Rules of the CEGB. It is a mandatory requirement that work on the current carrying parts of high voltage (HV) apparatus may be carried out only when those parts are earthed ('grounded'). Effectively, a H V system in the UK is one in which the difference of electrical potential between any two conductors, or between a conductor and earth, exceeds 650 V. For further information on the classification of systems by voltage in the UK, see the 'Memorandum on the 327
Switchgear and controlgear Electricity Regulations', published by HM Stationery Office. To meet this earthing requirement, all installations of HV switchgear have facilities for the connection to earth of all current carrying parts, i.e., all phase conductors. The switchgear in the power station plays a vital role in the procedures for work on station plant — particularly electrical equipment. It is, therefore, pertinent to refer to the circumstances giving rise to the design requirements described under the 'Design and Construction' sections which follow, concerning isolation and earthing. A fundamental requirement of the CEGB Safety Rules is that work on the conductors of high voltage equipment may be carried out only when the equipment is isolated from all sources of supply and, except in special circumstances, earthed. The switchgear provides the points of isolation. The protection of persons working on such apparatus afforded by earthing is dependent upon the combination of: • The efficiency of the connection of primary earths and their capability to carry the fault current until the electrical protective devices operate. • The speed of operation of electrical protective devices. • The system voltage, voltage gradient to the point of earthing and the fault level at the point of work. The Safety Rules (Electrical and Mechanical) recognise three classifications of 'earth', viz: 'primary earth', 'drain earth' and `metalclad switchgear movable earth' Primary earth
A fixed or portable earthing device applied at a position defined in a safety document. A primary earth must be applied within the isolated zone, and in accordance with the terms of a 'permit for work'. A path to earth established by closure of a circuitbreaker has, of course, the fault current carrying capability of the circuit-breaker, i.e., an ability to carry a current equal to the rated breaking current of the circuit-breaker for 3 s. Thus a circuit-breaker applied earth may serve as a primary earth anywhere on the system. The principles of application of a primary earth are: • With the exception of certain work on metalclad switchgear feeder, busbar and voltage transformer spouts (see below under `metalclad switchgear movable earths'), primary earths must remain in position until the associated permit(s) for work has(ve) been cancelled. • Where reasonably practicable, primary earths must be applied between the point of work and the point(s) of isolation. Where this is not reasonably practicable, any alternative procedure adopted must have specific approval. 328
Chapter 5 • Where primary earths are applied, all phases must be earthed except where work is to be carried out on phase segregated apparatus. Provided that all three phases of phase segregated apparatus are isolated, work may be carried out on one phase with a primary earth applied to that phase only. • Where possible, a circuit-breaker or purpose designed earth switch must be used to make the first earth connection. • When a non-fixed circuit-breaker, i.e., a circuitbreaker comprising a 'removable' or a 'withdrawable' part, is used to apply a primary earth, any automatic trip feature must, unless impracticable, be rendered inoperative before closing. After closing, any means of opening the circuit-breaker must be locked inoperative. • When a fixed circuit-breaker is used to apply a primary earth, all tripping functions must be rendered inoperative after closing, and the circuitthe closed position. breaker locked • Whenever reasonably practicable a circuit-breaker used to establish a primary earth should be closed from a remote control station, i.e., closure from local (at switchgear) controls should be avoided. Although the circuit-breaker has a proven full system prospective short-circuit current making capability, the avoidance of local control is considered to be a worthwhile precaution. Drain earth
A fixed or portable earthing device applied for the purpose of protection against induced voltages. Drain earths must be applied under the terms of a 'permit for work' or 'sanction for test' where induced voltages may cause danger at the point(s) of work. They are applied and removed as necessary during the course of the work or testing as specified in an 'earthing schedule'. Meta!clad switchgear movable earth
A portable earth applied to metalclad switchgear spouts before a 'permit for work' on the spouts is issued, which can be removed and replaced one phase at a time during the process of work being done under a 'permit for work'. The term 'spout' is used to describe the contacts in the switchgear enclosure from which a removable or withdrawable circuit-breaker or voltage transformer is disconnected when the circuit-breaker or voltage transformer is disconnected from the busbars or circuit. The use of the word 'must' without qualification in the earthing procedures described, indicates a mandatory requirement with no discretion permitted and no judgement to be made. Where a statement is qualified by the word 'practicable', a slightly less strict standard is imposed. It means that where it is possible to achieve, in the light of current knowledge and invention, but bearing in mind the hazards associated
General requirements vith the work to be undertaken, then the requirement
■must be met. Avoidance of the requirement is not
permissible on grounds of difficulty, inconvenience or cot. Where a requirement is qualified by 'reasonably judgement is required as to what is praciicable', a reasonable, taking into account the magnitude of the risk on the one hand and the cost, time and trouble, or effort necessary for averting the risk on the other. Where, in the case of high voltage metalclad switch,,ear having ;pouts, i.e., metalclad switchgear incorporating removable or withdrawable circuit-breakers, to be done on feeder or voltage transformer k‘ork is ,pouts, or on the busbar spouts of a single panel s‘\ itchboard, and the only position where primary earths be applied is at the spouts to be worked on, the can primary earths may be removed to allow the necessary access for work. The conditions under which work on each spout may then proceed are either: ca) By making use of `metalclad switchgear movable
earths', or, (b) After proving that each spout is at or about zero
potential by use of an 'approved' voltage indicator immediately before work is commenced; the voltage indicator itself being tested immediately before, and immediately after use. Where work is to be done on the busbar spouts of a multi-panel switchboard, 'primary earths' must be
applied to the busbars at one of the panels. The conditions under which work on each remaining spout may then proceed are either (a) or (b) above. It will be seen that work on the 'spouts' of the switchgear may be carried out either with or without the use of metalclad switchgear movable earths. The follown ,2 synopsis outlines the basic steps which must be other‘ed when work is to be done on switchgear \pouts.
(i'ork using inetalclad switchgear movable earths When carried out on the busbar spouts of a multi-panel switchboard using metalclad switch.2 ear movable earths, the following operations must be carried out in strict sequence: +■ ork is to be
(a) The section of busbars on which work is to be carried out must be isolated from all points of supply from which it can be made live, including any voltage transformers, the isolation arrangements locked and Caution Notices affixed. OA Where duplicate switches in one tank or on-load busbar selectors are installed — situations likely to be encountered only in the oldest stations — and it is impossible to isolate them from all points of supply, then all switches that can be closed onto the busbars on which work is to be carried out must be 'isolated' by having their mechanisms locked in the 'open' position.
(c) The shutters of spouts which are, or may become, live must be locked shut. Shutters of spouts on which work is not to be done must also be locked shut except for the busbar spouts at which the primary earths are to be applied. (d) Primary earths must be applied on the isolated section of busbars at a panel other than that on which work is to be carried out. If reasonably practicable, all primary earths must be locked in the earthed position. •
(e) Metalclad switchgear movable earths must be applied to all phases on the busbar at the points of work. (f) Danger Notices must be attached where applicable on, or adjacent to, the live apparatus at the limits of the work area. (g) A 'permit for work' must be issued. (h) The work may be carried out by a 'competent person'. The earths may be removed one phase at a time to give the necessary access. Each phase earth so removed must be replaced by the competent person before another phase earth is removed.
Note: A 'competent person' is one who has sufficient technical knowledge and/or experience to enable him/ her to avoid danger, and may receive, transfer and clear specified Safety Documents when nominated by an appropriate officer of the CEGB. (j) If it is necessary to carry out work on the spouts of a panel on which the primary earths have been applied, then after the work on the available busbar spouts has been completed, the permit for work must be cleared and cancelled. The primary earths may then be removed and replaced on the busbar spouts of another' panel on the isolated section of busbar. The procedure described in (e), (f), (g) and (h) above must then be followed. When work is to be carried out on the feeder spouts, voltage transformer spouts and single panel spouts using metalclad switchgear movable earths, the following operations must be carried out in strict sequence: (i) The spouts on which work is to be carried out must be isolated from all points of supply from which they can be made live and, where practicable, the isolation arrangements locked and Caution Notices affixed. (ii) The shutters of spouts which are, or may become, live must be locked shut. Shutters of spouts on which work is not to be done must also be locked shut. (iii) Primary earths must be applied to the circuit at each point of work and at all points of isolation, except where such points of isolation are 329
Switchgear and controlgear on the medium voltage or low voltage side of a transformer. Note: Under present UK legislation, the terms low
voltage' and 'medium voltage' have the following meanin2: Low voltage
A difference of potential between any
two conductors, or between a conductor and earth, normally not exceeding 250 V. voltage A difference of potential between any two conductors, or between a conductor and earth, normally above 250 V but not exceeding 650 V.
(iv) On the feeder, voltage transformer or busbar spouts on which work is to be carried out, the primary earths must be replaced by metalclad switchgear movable earths. (v)
If there are no other primary earths left on the circuit connected to the spouts being worked on, then while this work is in progress, no other work must be carried out on that circuit. Where the spouts are connected to a circuit on which there is any likelihood of induced voltages occurring, drain earths must, where reasonably practicable, be connected at the nearest point to the point of work where access to the conductors can safely be obtained.
(1,, i) Danger Notices must be attached where applicable on, or adjacent to, live apparatus at the limits of the work area. (vii) A 'permit for work' must be issued. (viii) The work may be carried out by a 'competent person'. The earths may be removed one phase at a time to give the necessary access. Each phase earth so removed must be replaced by the competent person before another phase earth is removed. Work without using meta/clad switchgear movable earths
When work is to be carried out on the busbar spouts of a multi-panel switchboard without using metalclad switchgear movable earths, the following operations must be carried out in strict sequence: • Operations (a), (b), (c) and (d) as for work using metalclad switchgear movable earths, followed sequentially by operations (f) and (g). • The work on the busbar spouts must then be carried out under the personal supervision of an 'authorised person', who must prove each spout dead by means of an approved voltage indicator immediately before the spout is worked on. The voltage indicator itself must be tested immediately before and immediately after use.
330
Chapter 5 • If it is necessary to carry out work on the spouts of the panel on which the primary earths have been applied, then after the work on the available busbar spouts has been completed, the permit for work must be cleared and cancelled. The primary earths must be removed and replaced on the busbar spouts of another panel on the isolated section of busbar. Danger notices must be re-affixed, a permit for work issued, and the work as described above carried out under the personal supervision of an 'authorised person'. Note:
An 'authorised person' is a 'competent person who has been nominated by an appropriate officer of the CEGB to carry out duties specified in writing'. When work is to be carried out on feeder spouts, voltage transformer spouts and single panel busbar spouts without using metalclad switchgear movable earths, the following operations must be carried out in strict sequence: • As in (i) for work using metalclad switchgear movable earths. • As in (ii) for work using metalclad switchgear movable earths. • Primary earths must be applied to the circuit at each point of work and at all points of isolation, except where such a point of isolation is on the medium voltage or low voltage side of a transformer. If reasonably practicable, all primary earths must be locked in the earthed position. • Where the work to be carried out will involve the removal of the primary earths at the point of work, then before a permit for work is issued alternative primary earths must be applied as close as is reasonably practicable to the point of work. However, if this cannot be achieved, then whilst this work is in progress no other work must be carried out on the circuit connected to the spouts being worked on. Where the spouts are connected to a circuit on which there is any likelihood of induced voltages occurring, drain earths must, where reasonably practicable, be connected at the nearest point to the point of work where access to the conductors can safely be obtained. • As in (vi) for work using metalclad switchgear movable earths. • As in (vii) for work using metalclad switchgear mo' able earths. • Work on the spouts must then be carried out only under the personal supervision of an authorised person who must prove each spout dead by use of an approved voltage indicator immediately before the spout is worked on. The voltage indicator itself must be tested immediately before and immediately after use.
General requirements When a fault making device or a circuit-breaker has been removed from its service position in preparaon for work, it must be immediately electrically ti discharged to earth. The application of primary or drain earths is then not required. After a fault making je%ice or a circuit-breaker has been removed from its ,orvice position and electrically discharged to earth, a •safety document' is unnecessary for the purpose of orkinc on the device or circuit-breaker unless the \t, ork is to be done whilst it is within the confines of sv,itchroorn or similar place, when a 'limited work a certificate' must be issued for the work. .4 Control The schemes of control provide for electrical 'close/ open' operation at the switchgear itself and, in most cases, from remote locations. Operation at the switchis designated 'local control'. Control circuitry dear is internal to the switchgear operates at the following °Wages: 3,3 kV and 11 kV switchgear
110 V DC
415 V and lower voltage switchgear: (a) Circuit-breakers
110 V DC
(b) Contactor gear
110 V AC/110 V DC
Generator voltage switchgear
110 V DC
Whereas local control operates directly into the cAviichgear 110V circuitry, that from remote locations and schemes of automatic/sequence control is usually at 48 V, via 48/100 V interposing relays mounted in the switchgear. Plant protective interlocks/trips and certain other control functions from external sources are, in general, connected directly into the 110 V circuitry. Trip circuit supervision is provided as a matter of course on all 3.3 kV and 11 kV switchgear, and on the principal 415 V and lower voltage circuit-breaker and latched contactor equipments. Supervision of 'closing' control circuitry is provided where closure immediately on demand is more essential than usual, i.e., in certain safety circuits. Selection of the mode of operation, e., local or remote, is made at the switchgear. Also provided at the switchgear are facilities for testing the closing and opening operation of the circuit-breaker Or contactor electrically whilst the main circuit controlled is disconnected (isolated) from the source of Supply
Because of the heavy power requirement of the closing coils of the majority of solenoid closed circuitbreakers, particularly at 11 kV, it is impracticable TO energise the operating coils directly at the control oltage of 110 V. Accordingly, such mechanisms are ', applied at a higher voltage, presently at 220V DC,
via 110 V/220 V auxiliary contactor type relays mounted in the switchgear. The adoption of 220 V DC for this duty is intended to discourage the use of such a supply for purposes other than switchgear operation. Prior to the introduction of this voltage for the duty, 240 V DC (a voltage employed generally for other power station services) was the rule. The DC supply voltages quoted above are derived from 'float-charged' batteries, normally of the leadacid type. AC supplies are usually obtained from control transformers located in the switchgear and fed from the 415 V main (power) circuit. However, the range of voltage appearing across the terminals of a battery of lead-acid cells — from fully-charged down to the loaded condition unsupported by the charger, at the limit of discharge compatible with the avoidance of damage to the battery — can be appreciably wider than that over which circuit-breaker mechanisms of the solenoid type are guaranteed to function satisfactorily. As explained later in this chapter, the current British Standards for circuit-breakers are BS4752 for voltages up to, and including, 1000 V AC and 1200 V DC, and BS5311 for AC voltages above 1000 V. The circuit-breakers in use currently, and for many years, in CEGB power stations are designed and tested basically to an earlier British Standard (8S3659) which specifies that closing mechanisms of the solenoid type shall operate satisfactorily over a voltage range, with operating current flowing, of 80% to 100% of the rated (nominal) value, whereas BS4752 and BS5311 require operation over the range 85% to 105%. Based on the requirements of the latter Standards, the minimum and maximum values of voltage acceptable at the terminals of a 220 V (rated) solenoid coil become: Minimum 0.85 x 220 V = 187 V Maximum 1.05 x 220 V = 231 V To meet a comparable operating voltage range, the rated voltage of a closing solenoid mechanism designed to BS3659 becomes (100/80)187 = 234 V. This value is also the maximum permissible at its terminals, i.e., the 100% value. For shunt-trip mechanisms, i.e., opening devices operated from a source of voltage separate from the main circuit, the limiting values of voltage at the terminals are 80% to 120% for devices to BS3659, and 70% to 110% for those to BS4752 and BS5311. In recognition of these requirements, control supply systems are designed to observe the following voltage limits at the incoming terminals of the switchboard whilst operating current is flowing: System nominal voltage (DC)
48 V
110 V
220 V
Maximum voltage
54 V
121 V
231 V
Minimum voltage
43V
96V
190V 331
Switchgear and controlgear The minimum value of 190 V for a system of nominal voltage 220 V DC allows for a 'volt drop' of about 3 V within the switchgear, i.e., between the incoming terminals of the switchboard and the terminals of the solenoid coil — the furthermost solenoid in the case of switchboard formations. To allow for voltage drop in circuitry external to the switchgear, e.g., in interlock circuits, it is necessary that 48 V and 110 V control relays be capable of functioning satisfactorily at values of voltage down to 39 V and 88 V, respectively. Operating supplies in switchboards are provided by buswires, sectionalised as shown in Fig 5.3. In normal operation, the sections are run electrically separate. However, an arrangement of links/fuses enables the sections to oe coupled in the event of loss of a source, but does not allow parallel operation. Parallel operation is precluded to minimise the risk of failure of one source interfering with the functioning of another. Where operating supplies are derived from 415/ 110 V transformers, two 100°70 rated units per switchboard or per section of switchboard are provided. They are segregated from one another, and located as far apart in the switchboard as is practicable. One pole of the 110 V winding is earthed. Depending upon the duty of the switchboard, each transformer is rated to supply a proportion of all electrically-held contactors in the closed state, together with a proportion of all contactors, both electrically-held and latched, in the process of closing simultaneously. To ensure proper functioning of AC-operated mechanisms, it is necessary to hold the output voltage of control transformers between 85% and 110°70 of the nominal value whilst operating current is flowing. The frequency is, of course, governed by the limits observed for the main (power) circuit, i.e., 47-51 Hz. Each single-circuit contactor gear unit is provided with a discrete transformer. Normally, each 110 V and 220 V DC system is earthed through an earth fault relay connected to the mid-point of a resistor across the positive and negative poles, the relay providing indication of faults to earth. 48 V DC systems normally have the positive pole connected directly to earth. Equipment energised from systems having the mid-point earthed through a relay is connected to the positive and negative poles of the supply through a fuse and solid link, respectively. Equipment fed from systems having the positive pole earthed is connected to that pole through a solid link, and to the negative pole through a fuse. Similarly, equipment fed from an AC source, is connected to the earth pole of the supply through a solid link and to the live pole through a fuse. To minimise the use of repeat relays, auxiliary contacts used for control, indication and alarm circuitry are, wherever possible, driven directly by the operating mechanism of that element of the switchgear to the movement of which the contacts are responsive. Thus, those contacts responsive to the change of state of 332
Chapter 5 the circuit-breaker/contactor, i.e., from open to close, and vice-versa, are activated directly by the switchgear closing mechanism. Likewise, those contacts responsive to the service and disconnected states of the switchgear are driven directly by the mechanism employed to select the service/disconnected conditions. However, the number of auxiliary contacts available so driven by the operating mechanisms of present designs of switchgear is limited. Accordingly, single-pole switching is generally the rule, arranged at present as follows: • In the connection to the positive pole of systems having the mid-point earthed. • In the connection to the negative (i.e., live) pole of the supply in control circuits having the positive pole earthed. • In the connection to the live (i.e., unearthed) pole of the supply in AC control circuits. Thus is preserved, in control circuitry, the basic convention of fusing and switching in the 'live' lead. In the case of mid-point earthing, the choice of pole to be fused and switched is arbitrary — both poles being at a finite potential with respect to earth. The fusing and switching of alarm and indication circuits is dealt with in Volume F.
1.5 Environment As a general rule, the switchgear is grouped into multi-circuit switchboard formations, accommodated in purpose built switchrooms. Exceptions are plantmounted items such as the control gear built into some designs of valve and other actuators. The switchrooms
should provide an environment in which the ambient temperature is held between + 10 ° C and 40 ° C — the upper limit being subject to an average value not exceeding 35 ° C over a 24-hour period — and the relative humidity should not exceed 70 07o whilst the switchgear is energised. Except for main circuit terminals, i.e., those terminals to which cabling external to the switchgear are connected, the upper limit of 40 ° C permits exploitation of the limits of temperature rise allowed by TEC Standards for switchgear. The temperature rise of main circuit terminals is held to a maximum of 50 ° C out of the necessity to limit the ultimate operating temperature to a value acceptable for elastomeric insulated cables. It is also necessary to ensure that the environment, particularly in the case of air-insulated gear, is substantially free of pollution by dust (especially from concrete surfaces), smoke, corrosive or flammable gases and vapours. Should there be circumstances necessitating the location of switchgear in ambient temperatures higher than cited above, the assigned full-load current rating is reduced to the value necessary to limit the maximum temperature likely to be attained in service, i.e., the average ambient temperature plus the permissible temperature
General requirements
1.11.1 CIRCUIT
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AC CONTRCN
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Flo. 5.3 Operating supplies in switchboards
333
Switchgear and controlgear rise, to values not exceeding those prescribed for the materials used in the construction of the switchgear.
2 Types of switchgear
2.1
Descriptions
The types of switchgear used on auxiliaries power systems in power stations in the UK comprise, broadly, circuit-breaker equipment, fused contactor controlgear and fusegear. For the purpose of this chapter, the following definitions have been adopted: Circutt-breaker A mechanical switching device capable of making, carrying and breaking currents under normal circuit conditions, and also of making, carrying for a specified time and breaking currents under specified abnormal circuit conditions, such as those of short-circuit. Contactor (electrically-held)
A mechanical switching device having only one position of rest, operated otherwise than by hand, capable of making, carrying and breaking currents under normal conditions, including operating overload conditions. Contactor (latched) A mechanical switching device operated otherwise than by hand, capable of making, carrying and breaking currents under normal conditions, including operating overload conditions, and fitted with a latching device. The latching device prevents the contactor from opening when the means of closure is de-energised. Thus a latched contactor is deemed to have two positions of rest. The contactor is opened by release of the latching mechanism electrically. Switch A mechanical switching device capable of making, carrying and breaking currents under normal circuit conditions, which may include specified operating overload conditions, and also of carrying for a specified time currents under specified abnormal circuit conditions, such as those of short-circuit. It may also be capable of making, but not breaking, short-circuit currents. ascontiector (isolator)
A mechanical switching device which provides, in the open position, an isolating distance in accordance with specified requirements. A disconnector is capable of opening and closing a circuit when either negligible current is broken or made, or when no significant change in the voltage across the terminals of each of the poles of the discornector occurs. It is also capable of carrying currents under normal circuit conditions and of carrying for a specified time currents under abnormal conditions,
Chapter 5 such as those of short-circuit. 'Negligible currents' imply currents such as the capacitance currents of bushings, busbars, connections, very short lengths of cables and currents of voltage transformers and dividers. 'No significant change in voltage' refers to applications such as the by-passing of induction voltage regulators or circuit-breakers. Fuse-switch
A switch in which a fuselink or fuse carrier with fuselink forms the moving contact, of the switch. However, an essential requirement is that the fuselink shall be disconnected on both sides when the switch is open. Thus arrangements in which the fuselink remains stationary during operation of the switch, but in so doing are disconnected on both sides when the switch is open, are generally accepted as qualifying as fuse-switches. Indeed, there is merit is not subjecting the fuselink to the shock of rapid acceleration and deceleration as is the case when mounted on the moving element. Almost without exception, the II kV switchgear is of the circuit-breaker type. At 3.3 kV, the practice is a little different. Whilst circuit-breaker gear is the rule generally for switchboard incoming supplies, busbar sectioning/interconnector and transformer feeders, the bulk of motor circuits, i.e., drives of up to the order of 1000 kW, have, since circa the mid-I960s, been handled by fused controlgear — known widely as 'motor switching devices' (MSD). However, more recently, such fused controlgear is, on occasion, used for transformer circuits up to 1000 kVA. Motors of rating above 1000 kW are usually controlled by circuitbreakers. At lower voltages, i.e., 415 V and below, circuitbreakers are normally employed for incoming and busbar section/interconnection duty on switchboards deriving supply from higher voltage sources; fused contactor gear and fusegear being the rule generally for motor control and distribution respectively. Where the scheme of protection allows, switchboards further 'downstream' may be fed via fuses — usually mounted in fuseswitches — switches or disconnectors (isolators). The reader wishing to research circuit-breaker theory and design in depth is recommended to study 'Power Circuit Breaker Theory and Design' published by Peter Peregrinus Ltd.
2.2 Testing and certification 2.2.1 General
All switchgear and associated equipment is type and routine tested basically to the appropriate British Standard, varied and/or augmented where necessary to satisfy a particular service requirement. Type tests are performed on one switchgear equipment of each type and rating, erected for the service
334
— JR
Types of switchgear specified, but ‘vithout the connection of external cablina. Essentially, the type testing demonstrates achievement of the specified 'rated values' in the following
the 'shaker' table, on which the equipment is mounted for test, must simulate.
al Ca S:
2.2.2 Certification
• Short-circuit withstand. The making and breaking of current under both
Wherever possible, types tests are carried out in accordance with the procedure defined in the relevant Standard. However, the values of the test quantities (e.g., current and voltage) may be varied from those prescribed in the Standard to satisfy a particular performance requirement. A point to be noted in this respect concerns the issue by Testing Authorities such as ASIA Certification Services in the UK, and the
• • •
normal and short-circuit conditions. Temperature rise in normal operation. Mechanical/electrical endurance.
• Dielectric (insulation) properties.
KEMA Organisation in The Netherlands, of certification of performance. The necessary documentation is normally provided in the form of a Certificate (of rating) or a Report of Performance. An example of the front sheet of a Certificate of Short Circuit Rating issued by the ASTA is shown in Fig 5.6.
Additionally, for switchgear in nuclear safety related
,.stems, testing is carried out to determine the ability to withstand prescribed levels of seismic event, i.e., earthquakes. Essentially, the switchgear must be demonstrated to be capable of withstanding, for a defined period — presently of the order of 10 s — horizontal and vertical 'floor' motion whilst performing any duty, c.v., an opening or closing operation on command, maintaining an open or closed condition, required in the course of a reactor safe shutdown procedure. F igures 5.4 and 5.5 show typical response spectra which
Certificate
A Certificate comprises a record of type tests strictly in accordance with a recognised national or international Standard. lt certifies that the equipment tested
1
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.
1.1
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04 05 06 0 7 08 09 0
5 6
7 s910
FREQUENCY,
20
30
40 50 60 70 80 90100
Hz
Fic. 5.4 Horizontal response spectra 335
Chapter 5
Switchgear and controlgear
2 5g
r m =I
.8
im
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I
5 0 t. DAMPING
29
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,
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50 60 70 80 90 100
FREQUENCY Hz
Ftc. 5.5 Vertical response spectra
has satisfied the requirements of the Standard and, by so doing, the ratings assigned by the manufacturer are endorsed by the Testing Authority. Report of Performance
A Report of Performance comprises a record of tests carried out in accordance with the instructions of the client — usually the equipment manufacturer. Reports of Performance are commonly issued to cover tests which, whilst they may have been carried out in accordance with the procedure prescribed in a recognised Standard, featured values of test quantities differing from those specified in the Standard. 2.2.3 Type tests
A particular departure from the requirements for type testing specified in the relevant Standard for 3.3 kV and 11 kV circuit-breakers (i.e., BS5311) concerns the number of operations to be performed during the 'mechanical' test. Here, the number of operating cycles specified presently is 2000, as opposed to the Standard requirement for 1000. It is expected that an even higher level of 'endurance' will be achieved by the designs of vacuum and SF6 circuit-breakers now under de336
velopment. Essentially, the number of cycles of operations demonstrated for the test is taken as indication of the frequency with which routine servicing should be undertaken. The type testing of circuit-breakers for electrical performance, i.e., current making and breaking capability, centres around the 'basic short-circuit test duties' and 'critical current tests' specified in BS5311 in the case of high voltage equipment, and the tests for 'verification of rated short-circuit making and breaking capacities' specified in BS4752 for lower voltage gear. The object of the testing is to prove the current making, breaking and carrying capability at any value of current up to and including the rated capacity at prescribed values of power factor, applied voltage, transient recovery voltage (TRV) and power frequency recovery voltage. Obviously the severity of the shortcircuit and normal conditions of the system in which the switchgear is to be installed must fall within the proven capability. Short-circuit test series
For the purpose of defining the short-circuit capability, and hence the suitability of a particular design in a
Types of switchgedr
Rating Certificate No.
ASTA
75 6 8
The Association of Short-Circuit Testing Authorities
(incorporated in the year 193ffl 8 Leicester Street. London WC2
Certificate of Short-Circuit Rating o
f
7 y A.
Ar. Air -13reak Circ uit Breaker Llnit with Spring closing mechanism.
Short•Circuit Type Tested in occordence with British Standard
3659: .1963
(with amendments)
11.0 kV.
Rated Voltage Maker
.
_asenceenali
Switchgear Limited. Liverpool.
Tested for Designation
Max. Rated Normal Current ..................
GEC Switchgear Limited. Liveryool.
1-
`../P
Serial No
The apparatus. constructed in accordance with the description, drawings and photographs sealed and anached hereto. has been subjected b y
Switchgear Testing Company Limited. to a complete series of proving tests of its short-circuit rating which has been made, subject to any observations in the record. in accordance with the appropriate clauses of the Specification(s). The res,Its are shown n the RECORD OF PROVING TESTS and by the oscillograms sealed and attached harem. The values obta,ned and the general performance are considered to justrly the Short•Circult Rating assigned by the manufacturer, an stated below
kV.
Breaking-capacity Symmetrical
. .kA
(Equivalent to
MVA.)
Making-capacity
.kA. peak at:_ll • C kV.
131+
52.6
Short-time current capacity for
3.0
LA. seconds.
IrA
Asymmetrical Duty
This Certificate applies only to the shon cicuil perfoirnance of apparalus made to the same nocification and haying the same essent.a' detalls as Ihe appa,atus tested.
The documents under seal forming part of this Certificate are
it)
1 - 12.
Record Of Proving Tests Sheets Nos.
,tt Nos (2) Our ograrns
Total of 28 itemized or. sheet No. 1.
i3i OtawlngS NOS
LL.5r7.10..1O122;
ii
:) , agrams has
Sp Photographs h as
LL.5312,/r87;
:i4A; D77; DEl; D 55 -.f51 - SP.
. 6
SP.,5.5•;11:-7;
- SP.5561,.
Lb
Secretary
Date
The conditions under which this Cérttlicate may be reproduced are governed by Clause 16 of ASTA Publication No. 2--tonditions tot Tess Work'.
Eio. 5.6 Example of the front sheet of a certificate of short-circuit rating of a busbar *stem, issued by the ASTA ( GEC Installation Equipment Ltd) 337
Chapter 5
Switchgear and controlgear given application, circuit-breakers are assigned a 'rated operating sequence'. BS5311 recognises two, viz:
• Breaking operations — breaking current: 100% of the rated breaking current, i.e, the RMS value of the symmetrical rated breaking current.
(a) 0-t-CO-t '-CO
• Making operations — making current: 100% of the rated short-circuit making current.
(b) CO-t "-CO where 0 represents an opening operation, CO represents a closing operation followed immediately (i.e., without any intentional time delay) by an opening operation, 1, I and I " are time intervals between successive operations. The intervals 1, t' and t " are indicative of the period of time which should be allowed to elapse before a circuit-breaker is called upon to repeat the clearance of short-circuit current. Similarly, the assigned rated operating sequence is indicative of the capability of the circuit-breaker to clear successfully repeated shortcircuits without inspection/maintenance. If, in sequence 0-t-CO-r-CO, the time intervals are not specified, then: • t = 3 min for circuit-breakers not intended for rapid auto-reclosing. • t = 0.3 s for circuit-breakers intended for rapid auto-reclosing (dead time). • t' ,= 3 min. In sequence CO-t "-CO, t" = 15 s for circuit-breakers not intended for rapid auto-reclosing. The rated operating sequence deemed appropriate for power station switchgear is 0-t-CO-r-CO, with time intervals t and t' both nominally 3 min but not less than 2 min. In general, there is no requirement for auto-reclosure, faults of short-circuit magnitude on power station systems are unlikely to be of a transient nature. The basic short-circuit test series to BS53I 1 consists of the following test duties: Test duty 1 Test duty 1 consists of the rated operating sequence confined to breaking operations only at 10% of the rated short-circuit breaking current with a DC component of less than 20%. Test duty 2 Test duty 2 consists of the rated operating sequence confined to breaking operations only at 30% of the rated short-circuit breaking current with a DC component of less than 20%.
Test duty 3 Test duty 3 consists of the rated operating sequence confined to breaking operations only at 60% of the rated short-circuit breaking current with a DC component of less than 20%. Test duty 4 Test duty 4 consists of the rated operating sequence with the following characteristic quantities: 338
For this test duty the percentage DC component must not exceed 20% of the AC component. When the characteristics of the test plant are such that it is impossible to carry out test duty 4 within the specified limits of applied voltage, making current, breaking current, and transient and power frequency recovery voltage, taking account also of the limits apertaining to the time interval t between tests, the making and breaking tests in test duty 4 may be made separately as follows: • Test duty 4a : making tests. C-t-C where the rated 0 operating sequence is 0-t-CO-V-CO, at 100 TQ of the rated short-circuit making current. • Test duty 4b : breaking tests. 0-t-O-t-0 where the rated operating sequence is 0-t-CO-r-CO, at 100% of the rated short-circuit breaking current. When test duty 4 is performed as 4a and 4b it is necessary, additionally, to demonstrate a 'make break' (CO) capability at values of voltage and current as near to the rated values as is practicable for the test plant. Test duty 5 Test duty 5 consists of the rated operating sequence confined to breaking operations only at 100% of the rated short-circuit breaking current, with a specified percentage DC component (see Fig 5.24). As stated previously, a DC component of 50% is specified for switchgear for use in CEGB power stations. Critical current tests The critical current of a switching device is a value of breaking current, less than the rated short-circuit breaking current, at which the arcing time is a maximum, and is significantly longer than that at the rated short-circuit breaking current. The manifestation of critical current, to a greater or lesser extent, is a feature of switching devices in which the efficacy of the arc extinguishing mechanism is a function of the value of the current interrupted, i.e, the efficacy increases as the current increases, and vice-versa. Circuit-breakers of the air-break type, i.e, circuit-breakers in which interruption of the arc takes place in air nominally at atmospheric pressure, are particularly prone to this behaviour. The problem in air circuit-breakers stems from the inability of arcs of relatively low current value to rise properly in the arc chutes, for reasons of thermal and/or magnetic effect. The situation is markedly improved by the expedient of directing a 'puff' of relatively low pressure air into the arc chute, beneath the arc; this 'puff' of air itself being derived
Types of switchgear ally from the circuit-breaker moving contacts damping mechanism. Tests for critical current are made on circuit-breakers likely to exhibit such characteristic at values of curthe rated short-circuit breaking rent less than ION or current. It is assumed that this is so if the average of i he arcing times in test duty 1 is significantly greater than that in test duty 2 usu
Single-phase lion -circuit tests
In addition to the above tests for short-circuit current making and breaking capability, for designs of circuitbreaker in which the contact systems of the three poles are coupled mechanically and provided with a common opening release, it must be demonstrated that the circuit-breaker is capable of breaking in an outer pole a current of not less than 100% of the rated breaking current. This test is necessary to show that the operation is not affected adversely by the unbalanced forces produced. Short-time current test
short-time current test is carried out to demonstrate the capability of the switchgear to carry, for its 'rated duration of short-circuit', a current of not less than its rated breaking current; the peak value of the first major loop of the test current being not less than that of the rated making current. The principal type tests applied to the designs of Fused equipment covered in Section 6 of this chapter, are described in the following paragraphs. Switching device in combination with fuselinks — Test duties 1, 2 and 3 in accordance with Publication No 22 of the Association of Short-Circuit Testing Authorities in the UK, an Organisation now incorporated under the name of ASTA Certification Services. A
Test duty 1 This test duty is an 0-t-CO sequence in a three-phase circuit having prospective symmetrical and peak currents not less than 100 0/o of the rated short-circuit values of the switching device in comhination with its fuselinks — the latter being fitted in all three phases. This test is carried out to verify that the complete switchgear assembly is capable of withstanding the cut-off current of the fuselinks, and that the striker pins incorporated in the fuselinks initiate Opening of the switching device correctly. Test duty 2
This test duty is an 0-t-00 sequence in a three-phase circuit, with fuselinks fitted in all phases, ha%.ine, a prospective current approximating to that Producing maximum arc energy within the fuselinks. This test is carried out to demonstrate that the complete switchgear assembly is capable of withstanding the maximum energy (I 2 t) let-through of the fuselinks.
Test duty 3
This test duty comprises one 0-operation on an outer pole, and repeated on the other outer pole, with fuselinks fitted in all poles, in a singlephase circuit having a prospective current not less than the rated short-circuit breaking current of the switching device in combination with its fuselinks. The test is performed to further verify that the complete switchgear assembly is capable of withstanding the cut-off current of the fuselinks, and that the striker pins incorporated in the fuselinks initiate opening of the switching device correctly. For the purpose of demonstrating the rated making and breaking current capability of the switching device in high voltage fused equipment the switching device itself is subjected to the series of short-circuit type tests applied to 3.3 and 11 kV circuit-breakers. This procedure proves: • The adequacy of the current making and breaking capability, having regard to the value at which the series-connected fuselinks 'take-over' the clearance of fault current. • The capability of the device to function as a circuitbreaker in a system, the fault level of which is within the rated breaking current capacity of the device, i.e., back-up fuse protection is not necessary. Additionally, the switching device is subjected to the tests for verification of rated making and breaking currents prescribed in BS775: Part 2: 1974: Clause 8.2.4 for Utilisation Category AC4. However, the value of the test current specified in the BS to prove the minimum rated breaking current — a value equal to 20 0/o of the maximum rated breaking current — may well not be low enough to demonstrate satisfactorily the behaviour if required to interrupt the load current of the smaller motors when 'running light'. Accordingly, the 25 opening operations specified in the BS to prove the rated minimum breaking current are carried out at a value of between 5 and 10 A. Earthing switches are type tested in accordance with BS5253 to prove the rated short-circuit current making and carrying capability; also the specified mechanical endurance. There is no breaking current requirement. Except for the circuit earthing device built into fused equipment in 3.3 kV systems, the short-circuit current making and carrying capability, i.e., the short-time rating, must be not less than that of the system switchgear. The circuit earthing device in fused equipment in 3.3 kV systems is required to be capable of making a current of not less than the maximum peak value of the short-circuit current of the system, but with the ti me element of the short-time current reduced from the 'standard' 3 s to 0.2 s. Switchgear and controlgear at all operational voltages is subjected to temperature rise tests to prove the rated normal current capability. Additionally, in the case of fused switching device equipment operating in 3.3 kV systems, a test is performed to demonstrate 339
Chapter 5
Switchgear and controlgear that the switchgear is capable of carrying for two minutes, without damage, a current equivalent to six ti mes the rated normal current. This test is applied to ensure that the switchgear has sufficient thermal capacity to handle the starting current of direct-on-line started motors for the longest run-up time likely to be encountered. As has been indicated, type testing is carried out on the switchgear assembled substantially as it will appear in service, albeit without the connection of service cabling, Thus the individual component parts, particularly busbar systems and main circuit elements, e.g., the circuit switching device and circuit isolating facility, are tested so assembled. With few exceptions to date, all low voltage circuitbreaker equipment, particularly in 415 V systems, is designed, constructed and type tested basically to BS3659: Specification for heavy duty air-break circuitbreakers for AC systems. Consequent upon the publication of BS4752: Specification for switchgear and controlgear for voltages up to and including 1000 V AC and 1200 V DC Part 1: 1977: Circuit-breakers, which Standard is itself identical to EEC Publication 157-1: 1973, BS3659 was withdrawn. The requirements of BS3659 are, in certain respects, more appropriate in the case of equipment for power station applications. However, it is policy to work to current Standards wherever possible. Thus, new developments in this field are subjected basically to the electrical and mechanical type tests prescribed in BS4752: Part 1, augmented by the following: • A three-phase short-circuit breaking test comprising an 04-0-1-0 sequence at a value of current not less than 100% of the rated symmetrical breaking current, plus a DC component in one phase at the instant of contact separation of not less than 50% of the peak value of the rated symmetrical breaking current. The method of determination of breaking currents is illustrated in Fig 5.24. Demonstration of this capability is necessary because the waveform of short-circuit current close to the source of generation can exhibit significant asymmetry for a number of cycles after fault inception. • A single break test at a value of current not less than 100€!0 of the rated symmetrical breaking current, at the appropriate phase-to-neutral voltage, applied to an outer pole. This demonstrates that the operation of the circuit-breaker is not affected adversely by the unbalanced forces produced. Main circuit contactors in contactor controlgear assemblies are, in addition to the type tests prescribed in BS5424: Part 1, subjected to the second test detailed in Clause 8.2.7 of BS5419, i.e., a current making test, for the specified prospective short-circuit current. For this test, and for the through-fault test prescribed for the contactor in BS5486: Part 1: Clause 8.2.3.2.3, elding of the contacts is not deemed a failure pro340
vided that no flashover occurs. This demonstrates the capability of the circuit assembly (functional unit) to close onto, and carry until operation of the circuit short-circuit protective device — usually fuselinks — any value of fault current consequent upon short-circuit anywhere on the load side of the circuit short-circuit protective device. Similarly, the through-fault and making current tests prescribed in BS5419 for the circuit (functional unit) disconnecting (isolating) device — usually a fuseswitch — demonstrates the capability of that device to close onto, and to carry until operation of the circuit short-circuit protective device, any value of fault current arising from short-circuit anywhere on the load side of the circuit short-circuit protective device. The busbar systems of switchboard formations of low voltage switchgear are tested for short-circuit withstand strength generally in accordance with the procedures prescribed in BS5486.
3 Generator voltage switchgear
3.1 Required performance By the late 1940s, the 'unit' principle had become the accepted pattern of the electromechanical design of power stations in the UK, where the main generator is connected directly to the lower voltage terminals of a generator transformer. Thus, for operational purposes, the generator and generator transformer operate as an electrically inseparable entity. Whilst station transformers are supplied at 132 kV from the National Grid system wherever practicable, this voltage level is not available at all power station sites. The high cost of switchgear and transformers at the alternative voltages of 275 kV and 400 kV has encouraged consideration of arrangements which, whilst preserving the essential features of 'unit' operation, would reduce the requirement for plant at these higher voltages. An obvious approach is the abandonment of conventional station transformers, together with their attendant switchgear, and the allocation of their duty to a combination of the Unit and Generator Transformer associated with each main generator. This concept, illustrated in Fig 5.7, necessitates the provision of means for disconnecting the generator at a point between its terminals and the unit transformer(s) tee-off connections. However, apart from issues of cost, the provision of such a disconnection facility can offer significant advantages operationally, particularly in nuclear installations. The performance required of the means of disconnection is governed by operational needs. The minimum capability of practical usefulness is synchronising the generator, the interruption of full-load current and the provision of an isolating facility — a duty calling for a switch disconnector. In essence, a switch dis-
Generator voltage switchgear bility of a switch disconnector as outlined above, the ability to interrupt fault currents of short-circuit magnitude. Wherever possible, the relevant design accords with the principles of British Standards 5311 and 5227. The first installations within the CEGB of generator voltage switchgear were those at its Hartlepool and Heysham / nuclear power stations, and its Dinorwig pumped-storage project. The concept has also been accepted for Heysham 2 and by the South of Scotland Electricity Board (SSEB) for the Torness and Inverkip power stations. To meet the system electrical parameters at the CEGB stations, the switchgear is rated as follows:
TRANSMISSION SYSTEM
GENERATOR TRANSFORMER
Hartlepool and Heysham 1 (generator MCR 660 MW) UNIT TRANSFORMERS
Rated voltage (operational) Rated normal current
23 kV 19.5 kA
Rated short-circuit breaking current Symmetrical
120 kA
Asymmetrical
150 kA
Rated short-circuit making current FIG. 5.7 The configuration of unit/generator transformers and generator circuit-breaker used as an alternative to the station transformer arrangement
400 kA peak
Rated duration of short-circuit
3s
Dinorwig (maximum capability, when generating, 313 MW) connector is capable of making, carrying and breaking currents under normal circuit conditions — whichmay Include specified operating overload conditions — and also of carrying currents under specified abnormal. circuit conditions, such as those of short-circuit, for a specified ti me. It may also be capable of making, hut not breaking, short-circuit currents. Additionally, it provides (when open) an isolating distance between the terminals of each pole. Thus, a switch disconnector used to disconnect a generator at generator terminal oliage must be capable of: • Nlaking, breaking and carrying continuously any ■.alue of current at any value of power factor up to the maximum load capability of the generator, e, full load, plus a specified overload, if required. -
• Carrying for a specified period of time, e.g., one
second, a specified value of fault (short-circuit)
Rated voltage (operational) Rated normal current
18 kV 11.5 kA
Rated short-circuit breaking current Symmetrical
105 kA
Asymmetrical
158 kA
Rated short-circuit making current
315 kA peak
Rated duration of short-circuit
I s
Heysham 2 (generator MCR 660 MW) Rated voltage (operational)
23.5 kV
Rated normal current
20.1 kA
Rated short-circuit breaking current Symmetrical
130 k A
Asymmetrical
170 kA
Rated short-circuit making current
400 kA peak
• Synchronising
Rated duration of short-circuit
!le ■■ ner, present thinking within the CEGB tends :051ards the use of a circuit-breaker, as this permits bc clearance of electrical faults in the generator without .iiszurbance of power supply to the unit auxiliaries. circuit-breaker used to switch a generator at generator terminal voltage has, in addition to the capa-
In addition to the basic performance outlined above, it is necessary to demonstrate the ability of the switchgear to deal satisfactorily with out-of-phase current switching and generator pole-slipping situations: also, that it does not cause unacceptable over. oltaee v. hen switch ing capacitive and transformer magnetising currents. It will be appreciated that the rated operational voltages listed above are the values for which the short -
the generator, including the making, but not breaking, of fault current arising from closure under out-of-phase conditions.
i
s
341
Switchgear and controlgear
Chapter 5
circuit performance of the switchgear is valid. However, to meet the standard of integrity required of the insulation of the switchgear/generator main connections combination, the following levels are specified: Rated impulse-withstand to earth
170 kV peak
Rated impulse withstand voltage across the disconnector in the open position (isolating distance)
195 kV peak
Rated power frequency (one minute) withstand voltage to earth Rated power frequency (one minute) withstand voltage across the disconnector in the open position (isolating distances)
LOY4
RESiSTOR ASSEMBLv
I N1ER R 1JPTER
X
70 kV RMS AUXILIARY INTERRUPTER 7\ 121
s'57- Ev
80 kV RMS
3.2 Design and construction
NON LINE' RES , STOm
/.1■1■11... MAIN GENERATOR
MAIN I NTERRUPTER
SERIES
FIG. 5.8 Diagrammatic arrangement of a multistae
interruption process
3.2.1 General The switchgear is of indoor-type construction intended specifically for connection directly into phase-isolated systems of generator main connections in a manner designed to preserve the principle of phase isolation described in Chapter 4: Generator Main Connections. Each pole of each three-phase assembly comprises an interrupter system connected in series with a disconnector (isolator). The series disconnector is necessary to provide the switchgear 'open' condition as, in the quiescent state, the interrupter system remains closed — opening, and remaining so, only for so long as is necessary to complete the process of arc extinction when interrupting the circuit, and to ensure against establishing current flow by the disconnector when closing the circuit. The disconnector also provides an isolating distance in free air, when open. The switchgear may, therefore, be used to isolate the generator electrically, provided that precautions are taken in the design of the scheme of control to safeguard against closure inadvertently when so employed. As already indicated, the interrupter in each pole comprises, essentially, a system of current making and breaking contacts, housed in an arcing chamber and connected in series with a disconnector. In its most basic form, the unit has a current breaking capability limiting its application to that of a switch disconnector, i.e., capable of load switching but not fault clearance, To increase the capability to that of a circuit breaker (the present requirement in CEGB installations), low ohmic value resistors and auxiliary interrupters are connected across the main interrupter to produce a two or three stage interruption process. The principle is illustrated in Fig 5.8. The process of interruption takes place sequentially as follows: (a) Main interrupter opens and an axial blast of air extinguishes the arc. 342
(b) Greatly reduced current flows through the loks value resistor assembly, the resistors damping the transient recovery voltage (TRV) which appears across the main interrupter. (c) The current through the resistors is interrupted by the auxiliary interrupters. Note:
Whether or not the auxiliary interrupters (1) and (2) open together (two stage interruption), or (I) before (2) (three stage interruption), depends upon the magnitude of the recovery voltage across the main interrupter. With low values of recovery voltage, the auxiliary interrupters open simultaneously; with high values, (1) precedes (2), the recovery voltage across the circuit-breaker being damped by the low value resistor assembly. A high value non-linear resistor connected across auxiliary interrupter (2) damps any overvoltage arising from the interruption of low value inductive current. (d) The series disconnector opens, interrupting any residual current flowing through the non-linear resistor. (e) The main and auxiliary interrupters close. The circuit-breaker is now open. Closure of the circuit-breaker involves the following sequence: • Main and auxiliary interrupters open. • Series disconnector closes. • Main and auxiliary interrupters close. In the matter of mechanical design, the main interrupters, which at rest take up the closed position, are
Generator voltage switchgear basically of the butt type in which the moving element presents a hemispherical face to the hollow conical surface of the fixed contact. When opening, the axial air blast flows over the surface of the moving contact and through a circular orifice in the centre of the fixed contact, see Fig 5.9.
MOVING CONTACT
FIXED CONTACT
INTERRUPTER CLOSED
FIG. 5.9
INTERRUPTER OPEN
Diagrammatic arrangement of a main interrupter
The contact system of the series disconnector comprises a telescopic arrangement in which a cylindrical drum contact moves axially to bridge two sets of fixed clusters of finger type contacts arranged in a circular formation, see Fig 5.10.
MOVING CONTACT DRUM
DiSCONNECTOR CLOSED
FIG. 5.10
oiscoNNec-roR OPEN
Diagrammatic arrangement of a series disconnector
The switchgear is operated by compressed air, the cin:uit interrupters utilising the air-blast principle. The poles of each three-phase unit are connected pneumatically to operate simultaneously; there is no mechanical interconnection across the poles. Each pole is provided with a discrete unit air receiver, charged at the switchgear operating pressure from a higher pressure toraee system. The capacity of each unit air receiver is sufficient for one close/open cycle of operation ithout replenishment from the high pressure store. Whilst the interrupter system of the switchgear at Dinorwig features one 'break' per pole for the electrical performance required, that for Hartlepool and Heysham / necessitated, at the time of placing the order, a double-break arrangement. However, development since has produced a single-break concept of corn,,
parable capability. Accordingly, the design accepted for Heysham 2 uses this arrangement.
3.2.2 Control Control of the switchgear is electropneumatie, operation is initiated by electrical activation of the pneumatic system. Each three-pole switchgear assembly is provided with a 'local' control panel of the free-standing cubicle pattern equipped with facilities for both local (at the panel) and remote control — selection of the method of control being made at the panel. Because of the noise of operation, personnel must wear ear protection near the panel when the switchgear is operational. This is an important consideration in the siting of the control panels. Examples of generator circuit-breakers are shown in Figs 5.11, 5.12 and 5.13. Figure 5.14 illustrates a circuit-breaker control panel.
3.2.3 Cooling The load current carrying duty of the switchgear necessitates forced cooling. The rating involved at Hartlepool and Heysham / and 2 requires a water system, whereas a forced-air scheme suffices for the much lower load current capability involved at Dinorwig. In the former arrangement, de-ionised water is circulated in a closed circuit through the switchgear phase conductors via a raw-water cooled heat exchanger. In the forced-air concept, the air in each pole enclosure is circulated by fan through an air cooled heat exchanger in such a manner as to leave that in the generator main connection trunkings largely uninvolved. Whereas in forced-air cooled installations each pole is dealt with individually — the equipment is an integral part of the enclosure structure — the plant for water cooled switchgear is provided on the basis of one discrete unit per three-phase assembly. Pump capacity in the latter is provided on the basis of two 100% units per plant. Typical arrangements of water cooling plant are shown in Figs 5.15 and 5.16.
3.2.4 Operating air plant The switchgear operating air plant is reserved wholly for that duty; it supplies no other station services. The capacity/rating of the high pressure storage/ compressor plant is determined by the number of operations of the switchgear to be 'stored', the length of time allowable for the restoration of the HP system to service pressure after a given discharge duty and the requirement that a compressor shall, at each start, run for a period sufficient to attain an acceptable working temperature. The Hartlepool and Heysham / projects are the first modern CEGB stations to feature the switching of main generators at generator terminal voltage. In these essentially base-load stations, the switchgear is called upon to switch relatively infrequently in normal 343
Switchgear and controlgear
FIG. 5.11
Chapter 5
Two poles (of a three - phase group) of a forced-air cooled generator circuit-breaker installed at Dinor‘sig
pumped-storage power station (British Brown-Boveri Ltd) (see also colour photograph between pp 496 and 497)
service. The high pressure storage/compressor plant
is, therefore, rated primarily to satisfy the needs of s witchgear commissioning initially, and of re-commissioning after overhauls. The present practice in baseload installations (Heysham 2 is a current example) is provision of air plant on the basis of: (a) A dual-pressure system in which air is stored in duplicate groups of high pressure receivers, from which it is fed at lower pressure to the switchgear local (unit) receivers. (In) One compressor plant per group of HP receivers, connected and controlled so that: • Each compressor can supply either or both groups of HP receivers. • Either compressor may be selected to 'run' or 'standby' when connected to supply both groups of HP receivers. • Both compressors can be run in parallel to supply either or both groups of receivers. (c
344
High pressure storage of the order of 5-close/ open cycles of operation of one 3-pole switchgear equipment without assistance from the compressor plant.
(d) Compressor capacity, i.e, both compressors running in parallel, capable of restoration to service pressure of the HP system after charging of the air receivers of one 3-pole switchgear equipment from atmospheric to operating pressure in a period of the order of 3 hours. Such compressor capacity is also capable of replacing the air drawn from the HP storage in 11/4 to 2 h running time in a 5-close/open switchgear operating duty. It should be explained that the ratio of 'high' pressure storage to 'operating' pressure is sufficient to ensure that expansion from one to the other results in the supply of acceptably dry air to the switcheear. The high pressure storage, and switchgear operating pressures are: 60 bar nominal
Hartlepool
High pressure storage
and Heysham /:
Swiichgear operating pressure 30 bar nominal
Dinorwig and
High pressure storage
Heysham 2;
Switchgear operating pressure
1 50 bar nominal 30 bar nominal
The normal operating regime at Dinorwie pumpedstorage power station entails a much heavier consumption of switchgear operating air than at Hartlepool and Heysham. These demands are supplied from three
Generator voltage switchgear
FR, 5.12 One pole of a forced-air cooled generator circuit-breaker, with side covers and the connection to venerator
busbar removed (British Brown-Boveri Ltd) (see also colour photograph between pp 496 and 497)
eparate (though interconnectable) dual-pressure comr[cN,or 'storage plants, i.e, one plant per two generator/ ror machines, each plant comprising high pressure ,:or..gc feeding a lower pressure switchgear operating The principle of storage at 'high pressure' and Ail,:hgcar operation at a lower value, is basically as Ilarlepool and Heysham / and 2. I L: Mr stora12.: capacity provided for Dinorwig pcimits v. ,. itching of the circuit-breakers, as to achieve the following station operating unassisted by replenishment from the cornr plant, commencing with the switchgear for genermor-motor open, i.e., all six three-phase -, ,
,
,.:: Aiii-h .reakers open:
• lick-to-hack starting of one machine in the pumpSic by another in the generating mode, culin a 'five machines pumping' condition. •
hangeocer to generation of the five machines
ilumpin2., i.e., all machines now operating in the ,zener,ning mode. • ,;t opping all six machines.
It was assumed that operational demand could call for the above sequence in a period as short as 45 minutes. It is, therefore, considered representative of the heaviest likely consumption of air during a length of time insufficient for make-up from the compressor plant to be of useful significance. The distribution of air to the switchgear receivers in the Hartlepool, Heysham 1 and Dinorwig installations is by ringmain. However, the design of the switchgear for the performance required for Heysham 2 demands air for the closing operation at a pressure marginally above that necessary for opening. Advantage is taken of the lower value required for opening to lessen the pressure on seals when the switchgear stands closed, that being the predominant service condition. This is achieved by automatic regulation of the pressure of the air supply to the switchgear receivers to suit the operating mode. It is, of course, essential that the circuit-breakers be capable of operating independently, i.e., allowance must be made for one standing closed — available for opening — whilst the other remains open — available for closure. Thus the operating air pressure requirement of one breaker 345
Jeabiolluop pue Jea6yol!ms Irir. 5.13 Flu - cc-phase water cooled genermor circuit-breaker sho ,wing conneerion into the generator phase-isolated bushar sysiem ( British Brown -Boyer' Ltd) (see also colour pholograplt li d weer' pp 496 :mil 497)
Generator voltage switchgear
FIG. 5.14 Generator circuit-breaker control panel (British Brown-Boveri Ltd) (see also colour photograph between pp 496 and 497) 347
Switchgear and controlgear
Chapter 5
Fic. 5.15 Cooling water plant (British Brown-Boveri Ltd) (see also colour photograph between pp 496 and 497) 348
Generator voltage switchgear
CIRCUIT BREAKER POLES I I 0-0441411 I
)
I I I
RED PRASE..-J
L r-1EADER
o
n YELLOW PHASE
c(4%Iro—c—o
o
0
BLUE PHASE I -J
-
VW-1-*
A
V
DEIONISING FILTER
HEAT EXCHANGER P U MPS
REGULATING VALVE
SERVICE COOLING WAT ER HEAT EXCHANGER' PUMP ASSEMBLY
FIG. 5.16
Cooling water plant schematic
at any given time, differ from that of the other. A simple ringmain system of supply cannot satisfy such conditions. Each unit is therefore, supplied separately. Figure 5,17 illustrates a typical operating air sysIC:111, Fif! 5.18 an air plant control panel, Fig 5.19 a Lompressor set, and Fig 5.20 a battery of high pressure (150 bar) air storage receivers. 3.2.5 Phase-reversal disconnectors for pumpedstorage schemes In the special case of Dinorwig pumped-storage power station, in addition to the use of generator circuithreakcrs, disconnectors (isolators) are necessary for phase reversal and machine starting purposes. As with generator circuit-breakers, the clisconnectors are of indoor type construction, designed for connection directly into the phase-isolated system of generator main Li nd starting busbars. Each pole of each group is driven separately by an electric motor in normal service, but v,ith provision for manual operation — the latter -
being intended primarily for use during maintenance. Mechanical and electrical interlocking prevents the si multaneous engagement of electrical and manual drives. Electrical operation may be from the 'local' control panel, or from a remote station, e.g., a control room — selection of the mode required being made at the local panel. The facility for remote operation is, of course, essential where the operational requirement necessitates a scheme of automatic control. An 'opento-close' operation, and vice-versa, electrically, takes approximately 5 s. The drive mechanism housing of each pole carries mechanical flag indication of the operated condition of each pole, i.e., 'open' or 'closed'. In essence, the mechanical construction of the contact system follows closely that of the series disconnector employed in the generator circuit-breakers at Dinorwig, except that natural, rather than forced, air cooling suffices. In addition, each pole features a glazed window on either side through which the position of the telescopic contact system can be observed. Figure 5.21 depicts 349
Jea6lailuoo pue Jea6qo
DRAIN VALVE LOCAL TO GENERATOR - - - SWITCHGEAR II
k
L___
_ COMPRESSOR C(2
I
ZTEL I
_
PRESSURE REDUCTION PANEL
r
_J GENERATOR SWITCHGEAR CONTROL PANEL
01
1 1
GENERATOR
t
PRESSURE MAINTAINING VALVE
COMPRESSORS
P1 - COMPRESSOR 1 COMPRESSOR 2 P3-ALARM
P2-
GENERATOR SWITCHGEAR LOCAL AIR RECEIVERS
GENERATOR 2
rWl
Foci. 5.17 Typical operaiiiig air . .,;ysiciii
Generator voltage switchgear
FR., 5.18 Air plant control panel (British Brown-Boveri Ltd) (see also colour photograph between pp 496 and 497)
\ingle-pole eNample of a disconnector with the top hdlt of the enclosure removed.
.1- he disconnectors, although off-load 'switching' de\ Lce ,, by definition, have a capacitive current breaking LIPability. For the purpose of uniformity of design and on , truction, all disconnectors, wherever positioned in [he 18 kV system, have an insulation level, normal current carr ■.i ng, and short-circuit current withstand capahilny matching that of the generator circuit-breakers.
,
3.2.6
Earthing switches
•\ recent introduction into CEGB practice is the use
of earthing switches for the earthing, during maintenance, of generators and their main connections. These switches comprise single-pole units designed specifically for incorporation into phase-isolated systems in such manner as to preserve the principle of 'phaseisolation'. Each pole of a three-phase group is driven individually by an electric motor, provision being made for operation local to the switch, or from a remote station. It can also be operated manually, primarily during maintenance of the switch, but only when the electrical drive is disconnected. Each pole carries a mechanical flag indication of the contact system position, i.e., 'open' or 'closed'. 351
Switchgear and controlgear
Chapter 5
Fin. 5.19 Typical air compressor set (British Brown-BoYeri Ltd)
The insulation level and short-circuit current withstand capabilities of the switches are, of course, matched to the requirements of the system of generator main connections. As throughout the power station, the earthing of main circuit (i.e., power circuit) conductors is attended by stringent rules governing isolation and making 'dead', supported, wherever possible and practicable, by electrical and mechanical interlocking — the latter often featuring the use of coded keys. The earthing switches described here are so interlocked. Each pole being operable independently allows closure to earth sequentially. Thus, in the event of inadvertent activation of a switch to dose — an act likely only in consequence of gross breach of CEGB Safety Rules — the closure of that phase alone would initiate the system earth fault protection; the fault current flow in such an event being limited by the neutral earthing resistor to a value within the 'making' capability of the switch. Figure 5.22 shows a single-pole switch dismounted, and Fig 5.23 a three-phase group connected into a phase-isolated system of busbars. Essentially, the switches comprise a fixed and moving_ contact assembly housed in a cylindrical enclosure of insulation material, mounted in each phase of the phase-isolated busbar system. The fixed contact is se352
cured to the busbar, the moving contact being driven down into engagement with it in a vertical plane. Heavy conductors connect the mounting flange of each switch of a three-phase group to provide a three-phase shortcircuit connected to the power station main earthing system.
4 3.3 kV and 11 kV switchgear — circuitbreaker equipment
4.1 Required performance The design parameters to meet system requirements for this switchgear are described in the following subsections. 4.1.1 Rated voltage
The rated voltage is the value of voltage used to designate the switchgear and to which is related its operating performance. The rated voltage indicates the upper limit of the highest voltage of systems for which the switchgear is intended. For polyphase systems it is stated as the RMS value of the voltage between phases.
3.3 kV and 11 kV switchgear
circuit-breaker equipment
FIG. 5.20 High pressure (150 bar) air storage receivers (British Broskri-Bm,eti Ltd)
353
Switchgear and controlgear
Chapter 5
Flo. 5.21 Single pole example of a phase-reversal disconneetor, with the top half of the phase-isolated enclosure removed and the unit in the open position (British Brown-Boveri Ltd)
Established designs, i.e., those evolved during the currency of B5162 and 1353659, are rated 3.3 kV or 11 kV, as appropriate to the system concerned. However, in order to align with IEC Standard values, the presently assigned ratings are 3.6 kV and 12 kV respectively. 4.1.2 Frequency and number of phases
This switeligear is al ■ ,,ays three-phase, 50 Hz. 4,1.3 Rated insulated level
"I he rated insulation level is the value of the impulse v,ithstand voltage and the value of the power frequency withstand voltage, which together characterise the insulation of the switchgear with regard to its ability to withstand the electric stresses. The 'classification' of the insulation of established designs — again those designs evolved during the 354
currency of BSI62 and BS3659 — is based upon the achievement of clearances between phases, and clearances phase-to-earth to the dimensions specified in those Standards for 'Class B', i.e., the higher of the two classes recognised. The 'insulation level' of such designs is determined by a combination of the specified clearances and the ability to withstand, for one minute, the prescribed value of test voltage. This is accepted as equivalent to the power frequency and impulse voltage test philosophy. The 'insulation level' of the newer developments, i,e, designs to B55227 and BS5311 are, of course, proved by test in accordance with Table 1, List 2, of BS6581: 1985 (IEC 694: 1980). 4.1,4 Rated short-time withstand current of main and earthing circuits
The rated short-time withstand current is the RMS value of the current which the switchgear can carry
3,3 kV and 11 kV switchgear — circuit-breaker equipment It is probable that system requirements in the future will be adjusted to accommodate the IEC rating of 40 kA at both 3.3 kV and Il kV, but for 3 s — the IEC standard value of 1 s being insufficient to permit satisfactory time grading of protection. 4.1.5 Rated peak withstand current of main and earthing circuits The rated peak withstand current is the peak value of the first major loop of the rated short-time withstand current which the switchgear can carry under prescribed conditions of use and behaviour. The present requirements are
HJ
• 3.3 kV system equipment A value equal to 2.55 ti mes the rated short-time withstand current, i.e., 2.55 times the AC component of the rated shortti me withstand current. This is the traditional value required by the older British Standards in consequence of the assumption that the maximum peak value likely to be attained by the first major loop of short-circuit current is 1.8 times the peak value of the symmetrical current, i.e., (1.8./2) x RN -IS value of the AC component of the short-circuit current. The standard IEC value, it should be noted, is 2.5 ti mes the rated short-time withstand current.
• 11 kV system equipment 121 kA. This, it will be noted, is approximately three times the RMS value of the AC component of the rated shorttime current. Whilst the standard value recognised by the IEC and, in consequence, by present British Standards for high voltage switchgear, is 2.5 times the RMS value of the AC component of the shortcircuit current, those Standards concede that higher values may be attained in certain circumstances. Instances of such are installations in which large gas-turbine generators are connected directly into the 11 kV voltage system and/or featuring a heavy motor load. 4.1.6 Rated normal current I I. . 5.22 SMO,..-pole earthing switch, dismounted (13rni,h lirown-Boveri Lid)
1or
a
;:oris
specified short-time under prescribed condi-
of use and behaviour. The present requirements
• 3$ k V rstem equipment — 26.3 kA or 43.8 kA for 3
N corresponding to system short-circuit levels of 150 \IVA and 250 MVA for 3 s, respectively (at 3.3 kV), both levels occurring in CEGB installations.
•
k I/
system equipment —
39.4 kA for 3 s; corto a short-circuit level of 750 MVA for at II kV.
repondinii 3s
Traditionally, the rated current of circuits and busbars is chosen from the ratings specified in BS3659, but, again to align with EEC ratings, they are now selected from the values listed in BS5311. To date, the maximum ratings required are 2500 A at 3,3 kV, and 3150 A at 11 kV. The rated normal current is permitted to take full advantage of the limits of temperature rise of current carrying parts accepted by the IEC. However, these values are, in the main, appreciably higher than those allowed by the superseded British Standards. This being so, to minimise the risk of damage to the insulation of the types of cable now in use, the temperature rise of the terminals to which they are connected is limited to 50 ° C, or such lower limit as may be specified in an apparatus specification. 355
Switchgear and controlgear
Chapter 5 1
••••
FiG. 5.23 Earthing switches installed on phase isolated generator busbars (British Brow n Bo■ eri Ltd) -
4.1.7 Rated short-circuit breaking current
(of circuit-breakers) • 3.3
system equipment:
(a) Symmetrical — 26.3 kA or 43.8 kA as demanded by the system fault level. (b) Asymmetrical — as the symmetrical value plus 50% DC component. • 1/ kV system equipment: (a) Symmetrical — 39.4 kA. (b) Asymmetrical — as the symmetrical value plus 50% DC component. The value 50% DC specifies the magnitude of the displacement from zero of the horizontal axis of the current waveform at the instant of separation of the circuit-breaker contacts which, added to the RMS value of the AC component of the current at that instant, determines the asymmetrical value. Figure 5.24 illustrates the method of determination of breaking currents. 356
-
A DC component of 50% is the 'traditional' value used in the UK for the specification of asymmetrical breaking current capability. It takes into account the opening time of the circuit-breaker to the extent that the X/R ratio of the system is normally not likely to be so high as to present a more onerous condition at he instant of contact separation. The British Standard currently appropriate to circuit-breakers for power station service is BS5311: 'Specification for AC circuitbreakers of rated voltage above 1 kV' — which itself derives from IEC Publication 56 — specifies values appropriate to the actual opening time of the circuitbreaker, based on a system X/R ratio of 14. However, the BS also recognises that in certain applications, e.g., where the X/R ratio is higher than 14, or if a circuit breaker is close to a generator, the percentae.. DC component of the system short-circuit current aveform may be higher than the value derived from the 'curve' shown in the Standard. A more detailed treatment of the significance of 'percentage DC component' is given in Clause 6.2 of BS5311: Part 2: 1976. 4.1.8 First-pole-to-clear factor
The first-pole-to-clear factor (of a three-phase system, and at the location of the circuit-breaker) is defined
3.3 kV and 11 kV switchgear — circuit-breaker equipment
D' AA = ENVELOPE OF CURRENT-WAVE EIB' CC = DISPLACEMENT OF CURRENT•WAVE ZERO-LINE AT ANY INSTANT OD = INSTANT OF CONTACT SEPARATION EE = Fl M S VALUE OF SYMMETRICAL CURRENT AT ANY INSTANT, MEASURED FROM CC x = PEAK VALUE OF AC COMPONENT OF CURRENT AT INSTANT DD' Y - DC COMPONENT OF CURRENT AT INSTANT DO y X 100 _ PERCENTAGE OF THE DC COMPONENT AT INSTANT DD' Isym SYMMETRICAL BREAKING-CURRENT OBTAINED FROM TEST RECORD = lasym = ASYMMETRICAL BREAKING-CURRENT OBTAINED FROM TEST RECORD
= V {{.*:2 I
y
Iprosp PROSPECTIVE BREAKING-CURRENT OBTAINED FROM A CALIBRATION RECORD FOR = TIME DD OF TEST RECORD FIG. 5.24 Determination of breaking currents
in
4.1.10 Rated duration of short-circuit
T he
1355311: Part 1: 1976 (Def. 6.25) as the ratio of power frequency voltage between a sound phase anti the other two phases during a two-phase shortwhich may or may not involve earth, at the locution or the circuit-breaker, to the phase-to-neutral olla:Ie which would be obtained at the same location \\ h the short-circuit removed. F or the purpose of testing, the first-pole-to-clear r,i,:tor is the ratio of the value of the power frequency rccacrv voltaae appearing across the pole in which current is first interrupted, to the phase-to-neutral 01t.itc of the test circuit. For power station service, he hkihest attainable ratio, viz 1.5, is used.
This is the maximum length of time for which the switchgear is guaranteed to be capable of carrying a current equivalent to its rated breaking current. It follows, therefore, that such is the maximum time for which protection may be allowed to delay tripping of the circuit-breaker on short-circuit.
41.9 Rated short-circuit making current
• 3.i kr system equiptnent 2.55 times the AC component of the rated short-circuit breaking current.
• //AV .s.s wern equipment 121 kA. The derivation of ilie factor 2.55 at 3.3 kV, and the value 121 kA at .
11 kV is explained in Section 4.1.5 of this chapter.
4.1.11 Rated operating sequence This is the sequence (0-t-CO-C-CO) on which the test duties for certification of short-circuit performance are based (see Section 2.2.3 of this chapter).
4.2 Design and construction 4.2.1 General As indicated in Section 2.1 of this chapter, the inter rupter in 11 kV switchgear is invariably, by definition, a circuit-breaker, whereas at 3.3 kV it is, depending 357
Switchgear and controlgear upon the duty, a circuit-breaker or a fused switching device. However, whether featuring circuit-breaker or fused switching device, the general form of design and construction of the switchgear as a whole, together with the operational facilities offered, are similar at both 3.3 and 11 kV. Those features peculiar to, and the service performance required of, fused switching equipment are dealt with in Sections 6.1 and 6.2 of this chapter, respectively. The switchgear is of the metalclad type, i.e., switchgear assemblies in metal enclosures intended to be earthed — complete except for external connections — and in which components are arranged in separate compartments with metal partitions intended to be earthed. Essentially, metalciad switchgear has separate compartments for: • Each main circuit switching device, e.g., the circuitbreaker. • Those components connected to one side of the main circuit switching device, e.g., the feeder circuit. • Those components connected to the other side of the main circuit switching device, e.g., the busbars. With few exceptions, the switchgear in service in CEGB power stations features circuit-breakers or fused switching devices of the air-break type, and was designed during the currency of British Standards BS162 and BS3659. However, fused switching equipment incorporating vacuum interrupters is gaining favour — particularly for frequently switched circuits. The exceptions in the circuit-breaker field are the few installations — generally to be found in the older stations — equipped with oil circuit-breakers, and sometimes themselves of the oil and compound insulated type. Whilst complying basically with the above Standards, the design overall features, of necessity, a number of operational facilities particular to power station service. However, it should be noted that the principal British Standards presently current in the UK for this class of switchgear are BS5227: Specification for AC metalenclosed switchgear and controlgear for rated voltages above 1 kV and up to and including 72.5 kV, and BS53 11: AC circuit-breakers of rated voltage above 1 kV — Standards based upon LEG Publications 298 and 56, respectively. The introduction of the newer British Standards has had no significant impact upon the performance and operational facilities required. Hence, designs to the superseded Standards are, for all practical purposes, accepted by the CEGB as compliant with the current publications. Nevertheless, to regularise the situation, the technical requirements of purchasing specifications are now couched in terms of the current British Standards. The switchgear is factory assembled, i.e., built-up into complete switchboard formations in the manufacturer's works, albeit dismantled into transport units for shipment to site. Each switchgear equipment, i.e., 358
Chapter 5 each circuit in a switchboard, is provided with a control and instrument panel forming an integral part of the switchgear cubicle. Wherever possible the relays required for the protection of the circuit are mounted on the control panel. However, where the space available on the control panel is insufficient to accommodate the total requirement, separate panels are provided on which all relays associated with the circuit concerned are mounted. That is to say, the relays specific to a particular circuit are all mounted either on the switchgear control panel, or on a separate panel — they are not divided between the two. Figures 5.25 to 5.31 depict typical II kV and 3.3 kV switchboard formations. 4.2.2 Enclosures Enclosures provide, when all doors and covers are closed, protection against the approach of persons to live parts to 'degree of protection' IP3X (see BS5227). Additionally, they are required to afford protection against dripping water, e.g., from condensation on switchroom ceilings. Thus the degree of protection provided overall is not less than IP31 to BS5490. To exclude also the ingress of vermin, the protection must be independent of the fitting of closing plates or other sealing arrangements at the point of entry of cabling into the switchgear. Normally the cable glanding arrangement adopted satisfies this requirement. Doors and covers, the opening of which gives direct access to main circuit conductors which may be live, are secured by fasteners the removal of which requires the use of tools, e.g., spanners, screwdrivers. Fasteners designed primarily for release by the use of a coin or similar implement are not accepted for this purpose. Alternatively, where for the purpose of attention to other apparatus it is necessary to gain access to compartments containing main circuit conductors, doors and covers are interlocked to prevent such access unless the main circuit conductors are de-energised. Doors and covers for which it is permissible to provide fasteners requiring neither tools for their release, nor involvement in a scheme of interlocking are, where it is desired to prevent unauthorised opening, provided with simple locking facilities — usually padlocking. In recognition of the stature and physical capability of the average male in the UK, apparatus mounted on switchgear is, wherever practicable, positioned within the following height limitations — measured from the operating floor level: Apparatus Operational controls, indicating instruments and indications, relay and relay manual reset facilities.
Height Max *450 ram
*2000 mm
Door and panel fastenings other than those of relay panels integral with the switchgear cubicle structure. *300 mm *2000 mm Protective and other relays required to be viewed from the outside of the switchgear, but not featuring manual operation.
450 mm
2600 mm
*Highest and lowest positions reached by an operator's hand.
0
3-
- -: ; - -!
.
IN
L] LI] __]
11 L I 0 41 CI -
00
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51)% BF PI
HEX UNIT TRANSFORMER
MY UNIT BOARD STATION BOARD INTERCONNECTOR
11E4 UNIT AUXILIARY TRANSFORMER I
1 0 FAN IA
1 0 FAN 113
PD FAN 1A
F 0 FUJI 1B
1200A CIRCUIT BREAKER
200(1A CIRCUIT BREAKER
20011A CIRCUIT BREAKER
120011 CIRCUIT BREAKER
12110* CIRCUIT BREAKER
1200A CIRCUIT BREAKER
1200A CIRCUIT BREAKER
1200A CIRCUIT DIFFUSER
DOOR Prom COLOUR BRILLIANT GREEN
DOOR SYMBOL COLOUR MIFIULE BROWN
DOOR SYMBOL COLOUR FRENCH BLUE
ODOR SYMBOL COLOUR ORANGE
DOOR SYMBOL COLOUR WHITE
00011 SYMBOL COLOUR ORANGE
DOOR SYMBOL COLOUR SIGNAL RED
00\
tr-i 0
o
0
[0 0 Ed
-
I
rzt
r " I [ 0 0A1
—r ] 0 ::0
C
ODOR SYMBOL COLOUR BLACK
C W HUMP I
START UP SIP 1
GAS TURBINE 1
1200A CIRCUIT BREAKER
I200A CIRCUIT BREAKER
2000A CIRCUIT BREAKER
DOOR SYMBOL COLOUR BRILLIANT GREER
DOOR SYMBOL COLOUR MIDDLE BROWN
ODOR SYMBOL
COLOUR
FRENCH BUN
Jea6pwAs A> I. L PueA1ET
H-
,
Fat. 5.25 Typical I I kV switchboard of Reyrolle manufacture
luaLudpba
—)- - - , f - -,
Switchgear and controlgear
Chapter 5
CIRCUIT IDENTIFICATION PLATE
ELAPSED TIME RECORDER
HEATER ON OFF SWITCH
OPEN CLOSE
REMOTE LOCAL SWITCH
VeITCH
CUBICLE TRIP BUTTON
SECONDARY ISOLATINC CONTACTS CLOSING LEVER PRASE SEPARATION BARRIER
SECONDARY CONTACTS
SECONDARY ISOLATING CONTACTS
CARRIAGE SYJITCH SHUTTERS
EARTH CONNECTIONS
SHUTTER OPERATING MECHANISM
MAIN EARTH FIXED•CONTACT
FIG. 5.26 Interior of cubicle fitted to the type of switchboard illustrated in Fig 5.25 360
3.3 kV and 11 kV switchgear — circuit-breaker equipment 4.2.3 Withdrawal/disconnection st without exception, the switchgear is of the A l mo \%ithdrawable type, i.e., the circuit-breaker is mounted wheeled carriage and hence is removable in Li ron oretv from the switchboard. This arrangement it cn not only a \.cry simple and effective means of ides conneetion (isolation) of an individual circuit from itchboard busbars, but also, by removal totally ,‘N he circuit-breaker from the switchboard structure, permits maintsmance work (on the circuit-breaker) away from the switchboard. This latter feature is of partir value in that work may be carried out on the "i a Jircuit-breaker outwith the CEGB Safety Rules aper,,iininu to work on high voltage electrical equipment. Upon removal of a circuit-breaker from its operaonal location it is necessary to cover the contacts by Il ,,t l ich it connects with the busbar and its circuit in the ,,,. iehboard. This is achieved by shutters closing over hc busbar and circuit contacts. The shutters, which must be of metal construction, are actuated automatically by the process of connection and disconnection of the circuit-breaker. Opening is by positive drive to minimise the risk of short-circuit upon re-entry of the ircuit-breaker into the 'service', i.e, 'connected' posic lion. Closing, if not positive, must be by two independent means — one of which may be gravity — cach capable of performing the closing operation alone. The use of withdrawable circuit-breakers facilitates ready access to busbars and circuits for testing purpoNes. To this end, provision is made, upon removal of a circuit-breaker from the switchboard, for opening and securing open, the shutters protecting the busbar contacts whilst those for the circuit remain closed, and ice- \.ersa. However, the means for securing the shutters in the open position are cancelled automatically and normal operation is restored upon reconnection of the circuit-breaker. Padlocking facilities are provided for lockine the shutters closed. When closed the shutters pro\ide degree of protection IP3X (see BS5227) against to the busbar and circuit contacts. To avoid risk inistake, the shutters are identified in accordance ,\ it h he following code:
cD1,-mr
Marking
Lettering colour
Minimum height of lettering, mm
Rd
13USBARS White
35
Lemon 35 .5
DANGER Red 537 LIVE CABLE
35
Lemon 3, ci
Viditionally, on busbar sectioning units, the section of husbar to which each group of disconnection contacts is .onnecteci is indicated by a white arrow on the asociaied shutter, pointing toward the relevant section of ,
bushar.
The means of disconnection of the circuit-breaker from the busbars and feeder circuits comprise off-load plug type contacts of the self-aligning pattern, suitable for use whilst the busbars and/or feeder circuits are live. Whilst in some designs disconnection is effected by withdrawal of the circuit-breaker carriage, in others it is achieved by the operation of off-load selectors. However, in all cases a system of mechanical interlocks ensures that the switchgear is locked positively in the required condition, i.e., connected for service, disconnected, or arranged for circuit earthing or, where appropriate, busbar earthing. Padlocking or coded-key devices are provided to permit enforcement of the required operational condition. Mechanical indication is provided to show when the circuit-breaker is in the 'service' or 'disconnected' position. The indicators are inscribed SERVICE or DISCONNECTED (or ISOLATED) in black lettering on a white background. Arrangements for isolation of the control and auxiliary circuitry when the circuit-breaker is disconnected (isolated) include: • Automatic disconnection of those circuits upon disconnection of the circuit-breaker or, alternatively; • Where such disconnection is not automatic upon disconnection of the circuit-breaker, purpose designed facilities are provided to permit such disconnection, if desired, when the circuit-breaker is disconnected. However, whichever arrangement is adopted, it must not be possible to restore the circuit-breaker to the service condition, i.e., reconnect, without reconnection of the control and auxiliary circuits.
4.2.4 Electrical interlocks Electrical interlocks for the prevention of closure of a circuit-breaker are arranged to interrupt the operating supply to the energising contactor of solenoid closing mechanisms, or the release coil of stored energy, e.g., spring closed mechanisms, as appropriate. Mechanical interlocks are required to be preventative, rather than curative, i.e., they are designed to prevent, as close as possible to the point at which manual force may be applied, an action of improper operation, rather than 'correct' the improper action. An example of this philosophy is the interlock provided to prevent connection/disconnection of a circuit-breaker, other than when open. Rather than initiate tripping of a closed circuit-breaker during the execution of the action of connection/disconnection, the interlock blocks the attempt positively.
4.2.5 Coded-key devices To assist the enforcement of operational and safety procedures, the switchgear is provided, where necessary, with coded key-operated devices whereby: 361
■
Jea6ianuop pue Jeabtowv s
0 o
o
0
0
0
A
0
0
0
Ili
EV
0
0
4
0
0
0
41
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e 1.•
I611
g]
0
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ri
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0
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.
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SYMBOL COLOUR AND CIRCUIT
WHITE LI STANDBY B.F. PUMP 36
BREAKER RATING
1300A
BUSEIAR /CUBICLE RATING CUBICLE TYPE CT. RATIO
L BLUE
II13 . 3 kV. STATION AUXILIARY TRANSFORMER I B
GREEN UNIT 3 I NTERCONNECTOR
YELLOW STATION TRANSFORMER 2
0 BROWN UNIT 4 I NTERCONNECTOR
E3 RED STATION BOARD I NTERCONNECTOR
EILUE I I / 3 -3kV.COAL ASH AND OK. PLANT TRANSFORMER 113
GREEN STANDBY 5.F PUMP 413
000A
2000A
3000A
2000A
2400A
800A
800A
2000A
20004
2000A
3000A
2000A
3000A
2000A
2000A
E7
El
El
ER
El
ER
E7
E7
I - $00/1 2 - 500/1 3-50015
VT. RATIO
I - 600/ I 3-60015
3-300011 3-3000/5 3PH.11000/110y
(a) 1 1 kV switchboard
FIG. 5127 Typical II kV switchboard or GEC manufaciure
3-250015
1-60011 3-600/5
1 500/I 2-500/1 3-500/5
,
2 3
13
4
LA
12
5
16
rr
4
— 2—
fin LAIL
6
11
15
24 -
10
fa
L L111
25 10
23
17
a
7
18
9
10
10 11 12
14—
— 20
19
011111111
13 14 15 16 17
TEM
18 19 20
(.0101.1. MC .1.. WWII!!
oNnt RvEXIAC11 PHOIIII;l I ON
Li
WI-PIE , STANDEE' III- PUMP
8L 1
,
111.
1 1i 3 ',OAT ION Au P A_IAR 1 RANSFOgMeR Ill
0
YEA1.0W STATION TRANSFONMEN
2
sin% BOARD 1 INTER CONNECTOR
r]
PLUS 11,33Av COAL ASH AND Oil Pt ANT THANSFORMER 113
(b) Separate relay panel for switchboard shown above
FIG. 5.27 (conrd) Typical II kV switchboard or GEC manufacture
G1AE EN ASTANC,13T F PUMP AA
21 22 23 24 25 26
'LOCATED INSIDE CUBICLE
luat_ud!nba Ja)ieaKi-l!nalp
13 8
FUSES AND i1/KIS 11 HIPPING CIRCU1T',-;) UNDERVOLTAGE PICITECT.ON RELAY (TRIPPING! UNDERVOLTAGE PROTECTION RELAY (TIMING) UNDERVOLTAGE PROTECTION RELAY CUBICLE ILLUMINATION MASTER SWITCH I NDICATING LAMP BLUE CUBICLE ILLUMINATION ON I NTERPOSING UNDERVOLTAGE RELAY SUPPLY SUPERVISION RELAY THERMAL RELAY (MOTOR PROTECTION) TRIPPING RELAY PRE—OVERLOAD ALARM RELAY I NDICATING LAMP WHITE TRIP CIRCUIT HEALTHY TRIP SUPERVISION RELAY OVERCURRENT RELAY BUCHHOLZ ALARM RELAY AMMETER CIRCUIT BREAKER CONTROL SWITCH B.E.F. PROTECTION RELAY STANDBY EARTH FAULT RELAY 1 NTERTRIP CIRCUIT SUPERVISION EARTH FAULT RELAY OVERCURRENT AND EARTH FAULT RELAY I NTERTRIPPING RELAY I NTERLOCK RELAY STANDBY INTERLOCK RELAY VOLTAGE SELECTION RELAY
JeaNalms A>I IL Pue M ET
REF NO",-,r.NGI A11114.
Switchgear and controlgear
Chapter 5
=PONT INSTRUMENT CHAMBER DOOR CONTROL SELECTOR SWITCH
Fic. 5.28 Interior of cubicle fitted to the type of switchboard illustrated in Fig 5.27 shown in the 'service' position 364
F(i. 5.29 "rypicat 3.3 kV switchboard of Reyrolle manufacture i[ sci., also colour photogiaph ht.awecu pp 496 and 497)
wawd!nba la>lealq-11.nolp
lea6(4o1!ms Ai
0.)
JeaBloJiuoo pue Jea5upl!ms 1•14... 5.30 'typical 3.3 kV switchboard of (IC manoraciure
3.3 kV and 11 kV switchgear — circuit-breaker equipment
removal of the key locks the circuit-breaker against connection in the service mode, it must remain possible to operate the circuit-breaker in either an earthing or the disconnected mode, or to place and operate an earthing switch in an earthing mode. 4.2.6 Identification of conducting parts
All main conductors are arranged, and identified with their phase colours, in accordance with B5158, The identification is specified to be of not less than 650 mm 2 in area at each location. The order of the phase connections is Red-Yellow-Blue. Essentially, for conductors arranged substantially in one plane, the positioning when viewed from the front of the switchgear, is as follows: • Run of conductors horizontal: Red phase top, left or farthest away. • Run of conductors vertical: Red phase left or farthest away. 4.2.7 Earthing of structures
Fir. 5.31 Interior of cubicle fitted to the type of itchboard illustrated in Fig 5.30; circuit-breaker ithdrawn, busbar and circuit shutters propped open
to) A key is free only when the circuit-breaker (or earthing switch) is closed in an earthing mode, i.e., to earth busbars or a circuit. Removal of the key locks the circuit-breaker (or earthing switch) in the dosed-to-earth condition. Each earthing condition is dealt with by a discrete device. hi
A key, when inserted and entrapped, permits closure of the circuit-breaker — it being free only when the circuit-breaker is open. However, attempted removal of the key when the circuitbreaker is closed must not initiate opening of the circuit-breaker. 3
% key when inserted and entrapped, permits the circuit-breaker (or earthing switch) to be closed in tin earthing mode only — it being free only when the circuit-breaker (or earthing switch) is open. As in (b) above, attempted removal of the key when [he circuit-breaker (or earthing switch) is closed must not initiate opening of the circuit-breaker (or earthing switch). Here again, as in (a) above, separate devices are used for the busbar and circuit earthing conditions. I
di A key is free only when the circuit-breaker is disconnected from the service condition. Whilst
Each switchboard formation is equipped with a main earth bar — usually externally at the rear at the base — to which `tee-off connections are made as necessary. The material may be copper, aluminium or an alloy of aluminium — specifications being B51432 for copper, and BS2898, material ElE or E91E, in the case of aluminium and its alloys. A clearance of not less than 15 mm is specified between the back face of the main bar and the adjacent surface of the switchgear enclosure to permit the attachment (on Site) of individual plant earthing cables. Joints in earth bars are kept to the minimum practicable. Where necessary, they are secured by screw fasteners, as are the connections thereto. Since experience has shown a need to avoid interfaces of electrotinned/aluminium surfaces — a combination likely to arise from the extensive use of aluminium conductor cable for earth bonding — copper earth bars are specified to be of plain, i.e., uncoated, finish. I mmediately before assembly of a joint or connection, the faces of aluminium/aluminium alloy conductors have the oxide fil m removed by, for example, steel wire brush, and the cleaned surface coated with petroleum jelly or other approved compound. Similarly, copper joint faces are cleaned and coated with petroleum jelly. Provision is made at each end of each switchboard main earth bar for connection to the power station main earthing system. This must present a flat area of not less than 50 mm x 50 mm (nominal). To deal with the fault levels likely to be experienced, earth bars of copper have a minimum sectional area and width — the latter being specified to ensure adequate area at joints, etc., — in accordance with the information tabulated below. Earth bars of 367
Switchgear and controlgear
Chapter 5 •••••
aluminium/aluminium alloy are specified to have a width not less than that for copper, and electrical and mechanical properties not inferior to that material.
Subsidiary (tee-off) earth bars
Main earth bar
Cross-sectional 2 area, mm
W idth, mm
300
50
Cross-sectional Width, mm 2 area, mm 150
25
Unless the positioning of the main earth bar itself is convenient for the purpose, tee-off connections are provided to facilitate the bonding to earth of cable glands. The metal framework of all withdrawable parts is connected to the earthing conductor through contacts designed specifically for the purpose. Such contacts are required to establish the connection to earth not less than 25 mm before establishment of the main circuit connections. Busbars and all conductors connected directly thereto are insulated. The insulation may be moulded or in the form of sleeving. It must be not less than 1 mm thick and capable of withstanding without damage the rated short-time current of the switchgear busbar system. To facilitate extension, busbars are of constant current rating throughout the switchboard. Although traditionally of copper, conductors of aluminium/ aluminium alloy are not precluded. However, where of the latter materials, the jointing procedure specified for earth bars would be adopted. 4.2.8 Circuit and busbar earthing
Each incoming/outgoing feeder circuit in a switchboard, and usually each single-circuit unit, is provided with means for earthing the circuit. Likewise, provision is made for earthing the busbars — usually at two locations on each electrically continuous, i.e., uninterruptable, section. Traditionally, the earthing on 3.3 kV systems is through the circuit-breaker in association with selector devices forming an integral part of the switchgear. However, on those units where it is necessary to provide for earthing the busbars as well as the circuit, mechanical interlocking is provided to prevent the use of both facilities simultaneously. At 11 kV, whilst some designs feature earthing through the circuit-breaker in association with selector devices forming an integral part of the switchgear, others use purpose designed earthing switches. Whichever arrangement is adopted it must preclude, at those locations featuring both busbar and circuit earthing, the earthing of busbars and circuit simultaneously. 368
Earthing switches have closing mechanisms of the dependent power solenoid or the stored energy spring.. operated type (see Section 4.2.18 of this chapter), and a rated short-circuit making current capability of n ot less than that of the circuit-breaker of the associated system switchgear. Closing mechanisms are provided with means for padlocking the switch in the closed position and, most importantly for safety reasons, it is not possible operationally to slow-close an earthing switch when connected for earthing operation. The basic specification for earthing switches is BS5253. The initial connection of busbars or circuits to earth, i.e., the connection to earth immediately following the making dead of the busbars or circuit, is completed by power closing the circuit-breaker or earthing switch, When earthing through the circuit-breaker, mechanical interlocking between the circuit-breaker and the earth path selector devices ensures that it is possible to prepare the switchgear for an earthing duty only when the circuit-breaker is disconnected from both the busbars and the circuit. Similarly, where earthing is through an earthing switch, mechanical interlocking is employed to permit connection of the switch only when it is open. Where access to the busbar and circuit disconnection (isolating) contacts may be obtained in the course of preparation of the switchgear for an earthing operation, provision is made whereby the automatic features of the shutter covering the group of contacts to be earthed remain operative, but that the shutter associated with those contacts not involved in the earthing operation remains closed and padlockable until the switchgear is restored to the service condition. Where, however, preparation of a switchgear equipment for an earthing operation neither involves nor permits access to the busbar and circuit disconnection contacts, the shutters may remain operable, as in the 'service' condition. To preserve the integrity of the connection of a busbar or circuit to earth, i.e., to reduce the possibility of inadvertent disconnection, means other than locking are provided whereby, when a switchgear equipment is prepared for an earthing operation through its circuit-breaker, the electrical tripping of the circuitbreaker is rendered inoperative, both during closing and when closed. Thus the circuit-breaker becomes a fault (short-circuit) current making and carrying switch and, as such, transfers elsewhere clearance of any fault current consequent upon inadvertent earthing of live conductors. However, the arrangements adopted for rendering the electrical tripping inoperative must be such that it is not possible to return the equipment to the service condition and to reclose the circuit-breaker without restoration of the electrical tripping. To prevent inadvertent earthing, padlocking or coded-key interlocking facilities are provided for locking earthing devices against selection into the earthing condition. Indication is provided to show when a switchgear equipment is prepared for 'CIRCUIT EARTH' or,
3.3 kV and 11 kV switchgear — circuit-breaker equipment appropriate, 'BUSBAR EARTH'. The indi, diere L'itions are by mechanical flag or, alternatively, by litablv positioned labels visible from the front of the ▪ equipment, inscribed CIRCUIT EARTH or BUSBAR \ RTH in black letters on a white background. The I . %c arranoements indicate merely that the equipo prepare'd for an earthing operation, and that ;nenl He earthed condition will exist only when the circuithreaker or earthing switch is closed. All conductors in the path to earth are required to o.c a rated short-time current of not less than that 1, : f he associated system switchgear. o In addition to the facilities for earthing busbars and circuits through the circuit-breaker or purpose deskilled earthing switches, portable devices are provided ' or application to the busbar and circuit spouts of voltage switchgear featuring withdrawable circuithigh breakers or fused switching devices. The devices may ▪ nre as 'primary earths', 'drain earths' and `metalclad ., itchgear movable earths'. Used as primary earths, the devices substitute for through the circuit-breaker, thus releasing the an earth cuit-breaker for servicing, etc., whilst work proceeds in parallel on the circuit. The devices are applied to the .N%ilehgear spouts in accordance with the procedure outlined in Section 1.3 of this chapter. For this duty, he devices must have a short-time current rating eapaHe of carrying, until the operation of protection, any \aluc of fault current which could materialise at the point of application in the event of energisation of the spouts to which they are connected. Being applied manually, the devices have no current making capability; hence the need to precede their application by an earthing operation through a circuit-breaker or an earthing s‘v itch having a fault current making capability. The use of the devices as drain earths and metalclad itch gear movable earths is governed by the procedure described in Section 1.3 of this chapter. Because, when used in the latter capacity, they must be suitable for application one phase at a time, the devices comprise single-phase units supplied in sets of three. 41.9 Auxiliary switches Ausilian, switches, i.e., switches for use in control and iliary circuits, are, wherever possible, driven posiiiv eh, in both directions. Only where the requirement iS or a greater number of auxiliary switches than can he dri‘en positively are interposing (i.e., repeat) relays permitted. However, every endeavour is made to allo,:aie the more important circuitry to switches driven Positively. Where necessary to satisfy, for example, sequence and interlocking arrangements, auxiliary switches arc provided which are responsive to the following , itcligear conditions: • Service (circuit-breaker connected for service). • Disconnected (circuit-breaker disconnected from the service position).
• Circuit prepared for earthing. • Busbars prepared for earthing. All auxiliary switches are wired, in accordance with 'standard' diagrams, to terminals in the fixed (cubicle) portion of the switchgear. Typical circuit diagrams, together with an associated terminal schedule, are illustrated in Figs 5.32 to 5.35. 4.2.10 Cabling arrangements All cabling external to the switchgear, together with glands and terminations, is normally supplied under a separate cabling contract, details of which will be found in Chapter 6 of this volume. All cable terminal chambers are positioned at the rear of the switchgear, the entry of cables normally being from below. With cabling connected, the insulation level of the terminal arrangement must be not lower than that of the rated insulation level of the switchgear. The physical disposition of main circuit cabling relative to that for auxiliary circuits at the point of entry into the switchgear enclosures is arranged to minimise the risk of a fault or fire on the main cabling affecting the function of the auxiliary cabling. Similarly, where the design of the equipment necessitates the installation of lengths of both main and auxiliary 'external' cabling within the enclosure, the arrangement adopted must again minimise the possibility of a fault or fire on the former damaging the latter. Essentially, this means the segregation within the switchgear enclosure of main from auxiliary cabling by earthed metal or mechanically robust fire-resistant material. Cable armour alone does not satisfy this requirement. Subject to minimum wire conductor sizes of 1.0 mm 2 and 2.5 mm 2 for individual circuits and bus-wiring respectively; ancillary electrical equipment, e.g., control and auxiliary wiring, control and selector switches, relays, etc., is specified in accordance with: • ESI Standard 50-18 for circuits operating at 100 V and above. • Engineering Recommendation SI7 for circuits operating at less than 100 V. These documents specify performance arid constructional requirements, together with guidance in matters of application. 4.2.11 Voltage transformers Voltage transformers are of the metal-enclosed dry type, complying with BS3941. They are normally installed on the 'fixed' portion, i.e., the cubicle of the switchgear, on the circuit side of the circuit-breaker — and thus within the protected zone. The method of mounting permits disconnection (isolation) from the main circuit and ready removal whilst the switchgear 369
Vow Switchgear and controlgear
Chapter 5
Ac CIRCUITS
ciRculT BREAKER ,CEI) Y ALTERNATIVE 5vy SC AGE AR AS SREciFIED
PROTECTION 0 RELAY AND • TEST FACILITY
CB LOCATION SWITCH
GB POSITION SWITCH
1 0VAC
0 _Tr; I
OUTPUT FOR REMOTE INSTRUMENT WHERE SPECIFIED1
ES
ho
• •
TEST 0 TERMINAL BLOCK 0 FOR ) EFFICIENCro METERING c
FIT C:I LIT F IB
C:1
FIT
INVERSE TIME UNDER VOLTAGE RELAYS 11•NAC BUSWIRES
12)
ROWER FLOW
Flo. 5.32 II kV or 3.3 kV switchgear — typical motor circuit 370
3.3 kV and 11 kV switchgear — circuit-breaker equipment
DC CIRCUITS 110.4 PC
220v DC OR 250v DC
CUOSNO COIL OR SPR,NG C.ARGE MECNAr,S..A T ROL SEr_ECTrON SmIrC rr REMOTE RAL
L OLA, I
1 1 1
L
60 1
7
ES .
I I . i
OPEN CLOSE
CB LOCATION SwrTcH
0----F0
01
cLoso.GcoNiAcTon
r0rLI: ; i ,
1
)
I
,
I ■
I
FL AN PROTECTION TRIP RELAn I NTERLOC oNS 01 F
0
I .
1
•C — OR
SPRING. RELEASE COkL. AND ANTI.PDIVP
CIRCUIT
L
---el-------1-9_0-0 I I=. r CB POSITION SWITCH
CB TRIP L NRISIT CONTACT TRIP COIL
— CE LOCATION SWITCH
1 70
,
PROTECTION
PLANT TRIPS TRIP CIRCUIT SuPERwSION
I
PS
RE
TRIP CIRCUIT SUPERVISION PRE CLOSE RELAN. TRIP RELAY VT TRIP PEAT
L. 3
1
0-0. 49 0 • 0
P3
TRIP CiRCruii SUPERVISION
AFTER-CLOSE ARA
TRIP CIRC W.11SUPERVISION RELAY LA 0:=Y1 ,...9, CATiON SWITCHES
UNOER VOLTAGE
ATAtAlIERAS
L31
CB POSIT ION SWITCHES
3
' 0-----0
a---
0■13
t
-
4
0
0
0
0-0
1 I
0
0
.
I
I
1
0—)-0
Cl-r,)
•
T ERNi iNALS FOR ES:CANAL CABLING
I 0—•-0 -
,r,r.■••-,
•9••■•■■-•-•,•
m-0 I 0— ■ )---0
R'E M0T LOCAL I TEST I I
—...C ■0
—
0. •
r
0--)-0
0•••--
-
/r0
Di
-0
I NTERPOSE RELAT OPEN
I NTERPOSE REL Av CLOSE
HEATER
'CIRCUIT PREPARED FOR EARTHING LOCATION SWITCH 0.••••••••••Cr.—.)
spRiNGCHAAGEO SWITCH 0--C ■r-0
SPRING FREE SWITCH
FiG. 5.32 (coni'd) 11 kV or 3.3 kV switchgear — typical motor circuit 371
Switchgear and controlgear
Chapter 5
WIRE No.
CABLE NUMBER APPLICATION
SWITCHGEAR ELEMENT OR FUNCTION
zw — co m cr j ..,
WIRE No.
INTERPOSE RELAY CLOSE
WI
101
W2
102
CONTROL SELECTOR SWITCH 'LOCAL'
. INTERPOSE RELAY : 'OPEN'
W3 W4
103 104
CONTROL SELECTOR SWITCH 'REMOTE
TRIP RELAY CONTACT
L101
105
L103
106
CONTROL SELECTOR SWITCH 'REMOTE
L109 L113
107 108
CB POSITION SWITCH N/O
1
015
207 208
PLANT PROTECTION INTERLOCKS
1(15 1(17
109 110
CE LOCATION SWITCH IWO
:
016 09
209
010
210
PLANT PROTECTION TRIP
1(5
111
CB POSITION SWITCH NIO
017 018
212
CB POSITION SWITCH N/0
020
TRIP CIRCUIT SUPERVISION CONTACT
■
K7
CB POSITION
& LOCATION SWITCHES WO
01
113
02
114
05
115
06
116
CB POSIT/ON
021
117
SWITCHES N/C
022
118
CB POSITION & LOCATION SWITCHES N/C
023
119
024
120
07
121
08
122
CB POSITION SWITCH N/O CB POSITION SWITCH N/0 CB POSITION SWITCH N/0 LOCATION SWITCH N/0 CB POSITION SWITCH NIC CB LOCATION SWITCH MC REMOTE AMMETER CONTROL SELECTOR SWITCH 'TEST'
I
I
.
EMI
CB POSITION & LOCATION SWITCHES N/0
& LOCATION
I
I _1
TERMINAL NUMBER
SWITCHGEAR ELEMENT OR FUNCTION
CONTROL/INDICATION
TRIPS & INTERLOCKS •
CONTROL/INDICATION
TRIPS & INTERLOCKS
NOT AVAILABLE WHEN
CB POSITION SWITCH N/C TRIP RELAY CONTACT
039
201
040 043
202 203
044
.
204
045
205
046
206
211
019 I
214 215
07 08
216
L105
217
L107
218
TRIP CIRcuiT
L115
219
CONTACT
L119
220
U/V PROTECTION RELAY CONTACT
047
221
046
222
UN PROTECTION RELAY CONTACT
049
223
050
224
SUPERVISION
011
123
012
124
013
125
LOCATION SWITCH
031
014
126
FOR EARTHING
032
CB LOCATION SWITCH Nr0
051
227
052
228
029
ELAPSED TIME INDICATOR FITTED
OCT PREPARED NOT AVAILABLE WHEN ELAPSED TIME INDICATOR FITTED
030
128
025
129
026
130
055 056
132
'SPRING FREE' SWITCH
C43/S43
133 134
CB LOCATION SWITCH WO
041
135
042
136
C411S41
131
'SPRING CHARGED' SWITCH
;
225 226
035
229
036 037
230 231
038
232
053 054
233
SPARE
137
1
234 235 236 237
FIG. 5.33 11 kV or 3.3 kV switchgear — typical motor terminal schedule
is live. Primary windings are protected by fuselinks, generally to BS2692 and, if necessary, current limiting resistors. It is possible to gain access to primary fuselinks only when the transformer is isolated. Secondary windings are protected by fuses in accordance with the requirements for ancillary electrical equipment and earthed at one point only. Each such earthing connection comprises a separately-mounted bolted link placed in an easily accessible position. The conductors from the main circuit to the point of connection to the voltage transformer primary fuselinks are sized to carry the rated short-time current of the associated circuit-breaker. 4.2.12 Current transformers
Current transformers comply generally with BS3938. 372
Except in the case of busbar sectioning equipment, current transformers are installed in the fixed portion of the switchgear, on the circuit side of the circuitbreaker. The secondary winding of each single-phase transformer and the star point of the secondary windings of each three-phase group is connected to earth at one point only, through a separately mounted 'captive' bolted link. Each. secondary winding is wired to terminals in the fixed portion of the switchgear. Primary windings are specified to be capable of carrying the rated short-time current of the associated circuitbreaker. To this end, 'bar' type primaries are used, wherever practicable. Where required for test purposes, terminals in the form of test blocks are provided on the switchgear for the connection of external instruments and metering equipment.
3.3 kV and 11 kV switchgear — circuit-breaker equipment 4.2.13 Control/selector switches he interest of uniformity, control switches are Ill t -it of, or below, selector switches, and located to the rid ti,nalls have pistol olp pattern handles. Padlocking lacilities are provided for locking control switches in 'neutral position and selector switches in each on. Control switches are spring-loaded to return neutral position when released.
:o 11(:
4.2.14 Switchboard/circuit identification as far as possible, the risk of injury to perncl and operational error through mistaken identio ri lication of circuits, labelling is provided as follows: Fo avoid,
switchboard or separately-mounted relay • On each panel. • On each circuit at front and rear, on the outside of the enclosure. Also, unless otherwise obvious, labels are provided to lientify the function of: • Fach control, selector, pushbutton and other switch, relw„ instrument, current and interposing transformer, transducer, indicator lamp, etc. Where relays are mounted away from circuit-breaker panels, each relay is labelled to show its circuit designation and the relay duty. • Each position of every switch. I ■ ternal circuit identification labels which, for prominence and clarity, are fitted on removable covers or parts are repeated on a non-removable part in or on the enclosure. AN an additional aid to identification, coloured symhols are provided at the front and rear of each circuit ui
a switchboard. These symbols are illustrated in 5.36.
4.2.15 Indicating instruments Indicating instruments and relays are of the flush-
mounted pattern. Ammeters are scaled to indicate fullHad current at approximately 75% full scale deflection. \ddirionally, those in motor circuits are usually of the ppressed scale type, i.e., suppressed at the upper end.
4.2.16 Test devices I or
the purpose of primary injection testing, portable L.1 0 ices are provided for the connection of test leads '0 th e
busbar and circuit disconnecting (isolating) con!ski, in the switchgear enclosure from which the circuithreaker
is disconnected when withdrawn. The devices must, when in position in the switchgear, be capable ot withstanding for 15 minutes a DC test voltage 01
System rated voltage, kV
DC test voltage, kV Phase/phase Phase/earth
3.3 11
10 36
7.5 25
The rating of the devices is dictated to some extent by the method of fitment to the switchgear. Generally, those for circuits rated up to and including 800 A are required to have a thermal capability of 400 A, and those for duty in equipment rated above 800 A, a thermal capability of 1000 A.
4.2.17 Circuit-breakers Circuit-breakers of the same type, current rating and circuit duty are required to be interchangeable; likewise, those of the same type and current rating, but of different circuit duty, subject to any modification necessary to control, indication and interlocking circuitry. Operating mechanisms are of the dependent power solenoid or stored energy type, provided with a shunt opening release and a mechanical opening release. The latter device must be available for use at all times, except when deliberately padlocked inoperable. In this context, 'available for use at all times' requires that, where the. release is located behind a door, the door must not be lockable. Indication of the closed/open state of the circuitbreaker is provided mechanically, and driven positively in each direction. The indication is inscribed: 'ON' in black letters on a white background, 'OFF' in white letters on a green background, and is operative whatever the duty mode, i.e., the 'service', 'disconnected', or an 'earthing' mode. Shunt opening release circuitry is taken through auxiliary switches driven by the circuit-breaker operating mechanism. It is necessary to switch the protection circuitry in such manner to ensure de-energising of such circuitry when the circuit-breaker is open. However, to ensure reinstatement of continuity when the circuit-breaker is closed, the switches are arranged to close before the main circuit is established. Locking facilities are provided, whereby the circuitbreaker can be prevented from being closed and also of being opened by operation of the manual opening device when closed in an earthing duty. Each of these locking requirements is met by the application of a single padlock, or a single key lock, and must not entail the fitting of loose components in addition to the padlock or key lock. Locking of the manual opening device is provided to prevent inadvertent opening of a circuit-breaker when used for an earthing duty. It must not, therefore, be possible to gain access to any part of the closing mechanism which would allow defeat of the locking of the manual opening device when the circuit-breaker is closed in an earthing duty. Whilst, when a circuit-breaker is employed in an earthing duty it is necessary to render inoperative its 373
IP' Switchgear and controlgear
Chapter 5
Al: CIRCUITS
SWITCHING PE VIC
AIR CIRCUIT BREAKERS ALTERNATIVE SWITCHGEAR AS SPECIFIED
DIFFERENTIAL PROTECTION RELAY AND TEST FACILITY
LL
WHERE SPECIFIED
I
CNEP 6 0 CURRENT ' AND EARTH FAULT PROTECTION o RELAY AND TEST FACILITY
OUTPUT FOR REMOTE INSTPLJMENT 'TRANSDUCER WHERE SPECIFIED)
POWER FLOW
FIG. 5.34 l I kV or 3.3 kV switchgear — typical transformer feeder circuit
374
3.3 kV and 11 kV switchgear — circuit-breaker equipment
DC CIRCUITS IEN DC
220V DOOR 250V DC
CLOSING COIL OR SPRING CHARGE MECHANISM CONTROL SELECTION SWI REMOTE
• O( AL CONTROL Syr ITCH NEUTRAL
LOCAL
OPEN CLOSE
T
.EMCFE
CLOSING MECHANISM
,C1CAL :
TEST
I
CB LOCATION SwiTcH
10 01
17,1,
CLOS:NG CONTACTOR OR SPRING RELEASE COIL AND ANTI-POMP CiFiCoiT
=
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LS
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or
04—R■ 3-0 I-S EATER
FIG. 5.34 teorit'd)
1
kV
or 3.3 kV switchgear — typical transformer feeder circuit
375
Switchgear and controlgear
Chapter 5
AC CIRCUITS
BREAkE
,,
CB
o =`,11,'-' 7,Ej';' ,TER.°AsTri2rMas REST.IC - E0 EARTH FAULT PROTECTION
- - 0 0 -LI
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32 11331 AC
BUS
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fo
01
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FR:, 5.35 11 kV or 3.3 kV switchgear — typical unit transformer circuit
376
3.3 kV and 11 kV switchgear — circuit-breaker equipment
CIC CIRCUITS
227, DC OP 2OTV DC
CE
io P
0
'
'• "EP LOG r , b
TO REMOTE PRE-CLOSE TRIP CIRCUIT SUPERVISION RELAY
a , , cEEP FPED0E ,C PI, O - ECT ■ ON
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r
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VOLTAGE CURRENT AND POWER TRANSDUCERS SHOWN IN BROKEN LINE WHERE SPECIFIED PTSE POST TRIP SEQUENCE EQUIPMENT
FIG. 5.35 (cont'd)
11 kV or 3.3 kV switchgear
—
typical unit transformer circuit
377
Switchgear and controlgear
Chapter 5
A
A
A
SIZE IN MILLIMETRES
BS 381C COLOUR NUMBER
COLOUR
REMARKS
DIM
FRENCH BLUE
166
A B
1
2
75
50
MIDDLE BROWN
411
25
16
BRILLIANT GREEN
221
25
18
CANARY YELLOW
309
65
55
SIGNAL RED
537
WHITE
W
BLACK
B
NOTES 1 PANEL No
I SHALL I N ALL CASES REFER TO THE PANEL ON THE EXTREME LEFT WHEN LOOKING AT THE FRONT OF THE BOARD LEFT HAND FUTURE EXTENSIONS SHOULD USE THE SERIES IN REVERSE. COMMENCING 42 41 ETC
gEmmmi n 3
SHAPE
5
6
7
12
13
18
17
19
20
21
22
23
24
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40
41
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39
42
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45
47
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,
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29
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25
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27
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E ZYU000
55 3810 COLOUR NUMBER
8
REPEAT
FIG.
5.36 Coloured symbols for additional circuit identification of switchgear
378
1111111mm
3.3 kV and 11 kV switchgear — circuit-breaker equipment electrically, the means adopted must not lock • ihe opening mechanism mechanically. To ntinimise the risk of physical injury to perwacred in the maintenance of a circuit-breaker, cr injury from inad‘ertent tripping of the operating H.e,:hanism, provision is made for slow closing and Whilst the means of slow closing/opening is use. movement of the circuit-breaker contacts must ifl under the control of the operator; opera:cumin v.holly n anual opening release must not negate ion of the function. However, to safeguard against attempted of a circuit-breaker other than by energy pro,[0,are its service operating mechanism, it must not Jed by he possible to use the slow closing facility when the ,ir,:uit-breaker is in the service position, or employed in an earthing duty. Except where for economic reasons it is desired o avoid the provision of heavy current DC battery t ,u rlies, no distinction is made as to technical merit N.qween closing mechanisms of the dependent power .olenoid or stored energy types. The interrupting systems of air circuit-breakers comri,c fixed and moving elements of the 'butt' or 'clip Jilt] blade' type, opening in 'arc chutes'. Both fixed inoN„ ing elements incorporate main and arcing conthe former for current carrying and the latter ior drawing the arc and relieving the former of the Lon,equential burning. The arc chutes comprise, essentially, enclosures of insulation material containing • large number of 'splitter' plates, which envelope each phase of the contact system. 13aically, the process of interruption is as follows: o pening
.
• The main contacts part, followed by parting of the arcing contacts. • An arc is drawn between the fixed and moving arcing contacts. • 'File arc is transferred during the motion of the m1)\ ing arcing contacts across 'arc runners' in the are chute.
• the arc is forced by thermal and, in some designs, deliberate magnetic effect into a lengthening loop in the arc chute, where it is split into many small series arcs, cooled and extinguished. a fact that the higher the energy of the arc, !he ! :!reater its propensity from thermal/magnetic influence t. o penetrate upwards into the arch chute. on ■ ersely, the lower the arc energy, the lower the ir klucernent so to do. Thus air circuit-breakers have cendency towards producing arcing times at low . =rerils significantly longer than those of currents C,il T the 'rated' breaking capacity. The current at arcing time is a maximum (termed the 'critical urrent') which may have a duration of many cycles, =s u•tially of the order of less than 5u7o of the rated 11
-
,
ipitci
To improve the performance at low currents, particularly at the higher voltages, an air 'puff', derived from the device(s) used to damp the arrest of the motion of the contact system at the open position, is directed at the underside of the arc to assist its movement upwards into the arc chute. The air puff is, of course, produced at each opening of the circuit-breaker, but is of useful effect only at low currents. By virtue of the relatively high arc resistance generated in air circuit-breakers, the transient recovery voltage (TRV) appearing across the breaker at interruption is well damped, i.e., air circuit-breakers are inherently 'soft' (see Section 10.5 of this chapter). 4.2.18 Circuit-breaker operating mechanisms Dependent power solenoid mechanisms are of the 'trip-free' type. Dependent power operation is defined as an operation by means of energy other than manual, where the completion of the operation is dependent upon the continuity of the power supply (to solenoids, electric or pneumatic motors, etc.). A 'trip-free' circuitbreaker is one in which the moving contacts return to (and remain in) the open position when the opening operation is initiated after the initiation of the closing operation — even if the closing command is maintained. However, it is recognised that, to ensure proper breaking of the current which may have been established, it may be necessary that the contacts momentarily reach the fully closed position. Means are provided for de-energising the solenoid coil immediately after the circuit-breaker has closed. The insulation materials of the solenoid coil are chosen to minimise the generation of flammable gases in the event of overheating of the coil through failure of interruption of the supply upon completion of the closing stroke. Additionally, the coil is, as far as is practicable, so positioned in the switchgear to minimise the risk of ignition of such gases from arcing of the main and/or auxiliary contacts during operation. Stored-energy mechanisms are of the motor-charged spring type. The definition of 'stored-energy operation', being 'an operation by means of energy stored in the mechanism itself prior to the completion of the operation and sufficient to complete it under predetermined conditions'. Such mechanisms are provided with electrical and also local (i.e., at the switchgear) manual mechanical release of the closing energy. The local release is usually, and preferably, by pushbutton, shrouded or recessed to prevent inadvertent operation and padlockable inoperative. With the circuit-breaker in the service position, recharging of the spring(s) is required to commence i mmediately and automatically upon completion of a closing operation. The recharging time must not exceed 30 s. It is further required that a charged spring(s) must not be released by the shock of operation of the circuit-breaker. Similarly, release of a charged spring(s) whilst the circuit-breaker is in the closed position must 379
1000 Switchgear and controlgear neither cause opening of, nor damage to, the circuitbreaker. Means are provided for charging the spring(s) manually. This permits a service closure, i.e., a full energy closure, if the spring charging motor or its electrical supply fails. Mechanical indication is provided to show the state of the spring(s). It is inscribed 'SPRING CHARGED' when the mechanism is in a condition to close the circuit-breaker and `SPRING FREE' when in any other condition. Where necessary, provision is made for indication of the state of the spring(s) at a remote point. Figures 5.37 to 5.44 show detailed views of the 1 I kV and 3.3 kV circuit-breakers and their cubicles, which form part of the switchboards illustrated in Figs 5.25 to 5.31.
5 3.3 kV switchgear — fused equipment
Chapter 5 short-time current capability of 26.3 kA for 3 s or 43.8 kA for 3 s, corresponding to system shortcircuit levels of 150 MVA and 250 MVA respectively, both levels occurring in CEGB installations, (b) All current carrying parts on the circuit side of the main circuit fuselinks are rated to carry the prospective rated short-circuit current of the busbar system, i.e, 26.3 kA or 43.8 kA, as limited in magnitude and duration by the highest rating fuselinks permissible in the switchgear. (c) All components forming a circuit path to earth have a rated short-time current of not less than that of the busbar system, except that the duration of the short-circuit current may be reduced to, but not less than, 0.2 s.
The technical specification for fused equipment is discussed in Section 5.2 of this chapter.
The rated peak withstand current capability of the components in (a) and (c), and the prospective peak value of the first major loop in (b), is 2.5 times the AC component of the rated short-time current.
5.1 Required performance
5.1.5 Rated normal current
Definitions and, where necessary, explanations of the rated characteristics are given in Section 4.1 of this chapter. 5.1.1 Rated voltage
Established designs, i.e., those evolved during the currency of British Standards BS162 and BS3659, are rated 3.3 kV. However, to align with IEC Standard values, the presently assigned rating is 3.6 kV. 5.1.2 Frequency and number of phases
This switchgear is always three-phase, 50 Hz. 5.1.3 Rated insulation level
The 'classification' of the insulation of established designs — again those evolved during the currency of BS162 and BS3659 — is based upon the achievement of clearances between phases and clearances phaseto-earth to the dimensions specified in those Standards for 'Class B'. However, here again, to align with present thinking within the IEC, the 'rated insulation level' is assigned in the case of the established designs, and specified to be proved by type test for the newer developments, in accordance with Table I, List 2, of BS6581: 1985 (IEC 694; 1980). 5.1.4 Rated short-time current
The present requirement is (a) Busbars and the conductors connected directly thereto, up to and including the busbar side terminals of the main circuit fuselinks, have a rated 380
Predominantly this class of switchgear is assembled into switchboards in association with circuit-breaker equipment. Accordingly, the rated normal current of busbars is chosen as described in Section 4.1 of this chapter for circuit-breaker equipment. The rated normal current of circuits is as declared by the manufacturer. To allow for the longest likely starting time (run-up to operating speed) of direct-on-line motor drives, each circuit must be capable of carrying for 2 minutes, without damage, a current equivalent to six times its rated normal current. This is in addition to the temperature rise limits specified in the relevant British Standards, and also the constraint of 50 ° C under 'rated normal current' with respect to main circuit terminals. 5.1.6 Rated breaking current of switching devices
Each switching device has a rated short-circuit breaking current capability, in accordance with BS5311, having an AC (RMS) component of not less than the 'takeover' current of the highest rating of fuselink permissible in combination with the switching device. The 'take-over' current of the fuselinks is defined as the RMS value of the symmetrical component at which the pre-arcing time of the fuselinks is equal to the minimum opening time of the switching device. The opening time of the switching device is defined as the ti me elapsing between the instant of energisation of the trip coil and the instant of separation of the contacts, no allowance being made for the operating time of other protective equipment. 5.1.7 First-pole-to-clear factor: 1.5
leabilowsns A1 EE 5.37 II kV air circuit-breaker shown withdrawn from the type of swiichboard illustrated in Fig 5.25
luawd!nba pasnj
i.
Switchgear and controlgear
Chapter 5
CUBICLE TRIP BUTTON LINKAGE ARC CHUTE
MIMIC DISPLAY
SECONDARY CONTACTS
In____\ OPERATIONS COUNTER
AUXILIARY SWITCHES
\P tatofee
ilic iticgactirg lai? algititIttlii y 1. alM■ NV_ r
CUBICLE RELEASE MECHANISM
14 k, N
AUXILIARY SWITCHES 11MV BUSHING
ANTI PUMPING RELAY
OPERATING HANDLE APERTURE RACKING IN CAM
PIVOT WHEEL LOCK ASSEMBLY OPERATING SHAFT
AIR CYLINDER
MANUAL TRIP BUTTON
ARC CHUTE SPLASH PLATE
ISOLATING MECHANISM ASSEMBLY
CLOSING CONTACTORS TRIP COIL
MAINTENANCE HANDLE SHUTTER
TRIP MECHANISM
FIG. 5.38 Front view of 11 kV air circuit-breaker shown in Fig 5.37 with covers removed
382
3.3 kV switchgear — fused equipment
SECONOARY ISOLATING
CONTACTS
ARC cRLITE
CIRCUIT ISOLATING CONTACTS
RACKING I N CAM
BUSBAR ISOLATING CON racrs
SOLENOID OIL DASRPOT
FIG. 5.39
Rear viev, of II kV air circuit-breaker shov, n in Fig 37
383
Chapter 5
Switchgear and controlgear
A .0 .B. CLOSED INDICATOR (RED)
CONTROL SELECTOR SWITCH
SAFETY KEY
ON - OFF NO COMBINED STEERING AND RACKING HANDLE
SERVICE-EARTH-TEST I NDICATOR
EARTH SELECTOR KEY
INTERLOCK SELECTOR BOLT
SPRING-LOADED PIN
TWIN DOLLY WHEELS AND RACKING GEAR PULL TO CLOSE LANYARD FOR MANUAL A .0 .8 . OPERATION
Fic. 5.40 Front view of 11 kV air circuit-breaker fitted to the type of switchboard illustrated in Fig 5.27
5.1.8 Rated short-circuit making current
In addition to the requirements of BS5311, switching devices are capable of making and latching closed against a prospective current equivalent to that of the 384
system in which the switchgear will be installed, as li mited in magnitude and duration by the highest rating fuselirik permissible in combination with the switching device.
3.3 kV switchgear — fused equipment
Fic. 5.41 Rear view of 11 kV air circuit-breaker shown in Fig 5.40
385
11111■1'Chapter 5
Switchgear and controlgear
ARC CHUTES
SECONDARY CONTACTS
SECONDARY CONTACTS
SEMAPHORE INDICATORS
OPERATIONS COUNTER
EARTHING SELECTOR HANDLE
ISOLATING MECHANISM SELECTOR HANDLE
MECHANICAL TRIP BUTTON
AUXILIARY SWITCH 51
ANT PUMPING RELAY AUX 8
CLOSING CONTACTOR
AUXILIARY SWITCH 52
CLOSE COIL PROTECTION AUX 9
OPERATING MECHANISM
PRESS FOR SLOW OPENING
AIR CYLINDERS
Flo. 5.42 Front view of 3.3 kV air circuit-breaker shown withdrawn from the type of switchboard illustrated in Fig 5.29
386
3.3 kV switchgear — fused equipment
Flo. 5.43 Rear view of 3.3 kV air circuit-breaker shown in Fig 5.42
387
Switchgear and controlgear
FiG. 5.44 3.3 kV air circuit-breaker shown withdrawn from the type of switchboard illustrated in Fig 5.30 388
Chapter 5
3.3 kV switchgear — fused equipment
5.1.9 Rated duration of
One
short circuit -
second, subject to the '2 minute' rating described
under 'rated normal current'.
5 1.10 Rated operating sequence • •
F:quipinent ‘‘ith fuselinks fitted, 0-t-CO. S\N
itching. device without fuselinks,
Co-ordination of switching device with 5,1.11 fuse protection .\„ ex ample of co-ordination of the current breaking ,:apability of the switching device with the short-circuit fuse protection is given below. Parameters assumed: •
Motor starting current, 4.8 x full load current (see 13S4999: Pt.41: 1972: Table 41.4: Col. 3).
The above examples serve to illustrate the philosophy of the relationship of motor rating to the capability of the fuse/switching device combination. Breaking current capability and opening times of the order of 11 kA sym and 40 ms, respectively, are typical of contemporary air-break switching devices in the UK. Development is in hand in the vacuum-break device field to at least match the capability of the air-break designs. The 'two successive starts' requirement is because all motor drives in a power station must be capable of this without overheating. As precise details of starting current and duration are seldom available at the time of placing controlgear contracts, experience has shown the 20 s per start allowance to be a 'safe' assumption. The principle is illustrated graphically in Fig 5.45.
TIME
• -1- %■ o successive starts each of 20 s duration. • Opening time of switching device, 40 ms (see definition of opening time under 'rated breaking current of s witching devices). • Fuselinks `derating factor' 1.8 (this is, in effect, an 'anti-deterioration factor').
Now.:
The following calculation is based on 'nominal'
salues, i.e., all performance tolerances are ignored:
Motor rating Full load current
1200 kW 244 A
Starting current (4.8 x 244) = 1171 A Allowing for the fuse derating factor, starting current is assumed to become 1.8 x 1171 = 2108 A. To carry, without operation, for a period of 2 x s = 40 s, a current of this value, fuselinks of UK manufacture (i.e., fuselinks to BS2692) require to have a continuous current rating of the order of 400-
STARTING CURRENT
STARTING SWITCHING DEVICE CURRENT 18 NONIMUM BREAKING CURRENT CURRENT
Principle of co-ordination of fuselink rating with switching device current breaking capability and motor rating
Pic. 5.45
4{) A .
The 'take-over' current (see definition under 'rated breaking current of switching devices') of fuselinks of he order of 400-450 A, i.e., the pre-arcing current [hey will carry for a period equal to that of the open-
[rig ti me of the switching device, requires that the itching device shall have a rated breaking current of the order of 11 kA symmetrical (sym). It follows that the lower the breaking current capability of the switching device, the lower the rating of 11e back-up fuse protection and hence the smaller the rating of motor which may be handled. Typically, in d so itching device of 5 kA sym rated breaking current, th maximum permissible rating of the fuselinks would be of the order of 250 A. This in turn would, on the basis of two successive starts each of 20 s duration, li mit the size of motor to approximately 600 kW. S1.1
5.2 Design and construction 5.2.1 General It was remarked at the beginning of Section 4.2 of this chapter, that whereas the interrupter (the circuit switching device) in 11 kV switchgear is invariably a circuitbreaker, at 3.3 kV, depending upon the duty involved, it may be either a circuit-breaker or a fused switching device. It was further pointed out that, whether featuring a circuit-breaker or a fused switching device, the general form of construction of the switchgear and the operational facilities provided, are similar. Accordingly, the only features dealt with here are those particular to the design and construction of fused 389
Ci
Switchgear and controlgear switching equipment or those which, in the interest of clarity, are felt to merit further discussion. In the early 1960s, there were explosions in the terminal boxes of 3.3 kV motors from flashover across the surface of the filling compound then common. As a consequence, in addition to improvement of the design in his area, the concept of limitation of fault current energy by the use of fuses was introduced. Initially the application of this philosophy took the form of series-connected high breaking capacity (HBC) fuselinks in boxes adjacent to the motors, followed by incorporation of the fuselinks in the switchgear. It should, perhaps, be stated here that the backing of switching devices, e.g., circuit-breakers, contactors, by fuselinks was then, and remains presently, a well established practice — adopted primarily to deal with currents of a magnitude beyond the making and breaking capability of the switching device. Whilst, as will be explained, this is now the situation in CEGB practice, the switchgear into which the fuselinks were fitted initially had the full system fault level capability unaided by the fuselinks. Since the mid 1960s, the switchgear used to control 3.3 kV motors up to around 1000 kW has incorporated HBC fuse short-circuit protection — advantage being taken of the fuse characteristic to reduce the fault current switching capability required of the switching device, and thereby produce a more compact and less expensive design of switchgear for the duty. However, a pre-requisite of the development was maintenance of the operational facilities of the existing switchgear with no reduction in reliability. 5.2.2 Duty of switching device and circuit earthing facilities
The duty of interrupting the higher values of overcurrent (which may be many times the current manifested during the starting of motors direct-on-line) having been taken over by the fuselinks, such capability on the part of the circuit switching device became superfluous. The 'scaling down' of the switching device thus possible, permitted appreciable reduction in the overall size of the switchgear together with significant saving of capital cost. However, the reduction in fault current capability of the switching device meant that it could not itself serve as the circuit earthing device. (Note: busbar earthing facilities are not required on switchgear controlling motors.) Accordingly, each switchgear equipment of this type is, in addition to the circuit s witching device, equipped with a circuit earthing switch capable of making and carrying, until the operation of protection elsewhere, any value of fault current which could appear accidentally on the circuit. The circuit earthing switch is padlockable in the closed position. Because in an earthing operation it is essential that the earth path must at all times be electrically continuous, the earth switch is arranged to by-pass the circuit HBC fuselinks. 390
5.2.3 Switching devices
Like circuit-breakers, fused switching devices of same type, current rating and circuit duty are requi, to be interchangeable, as also are those of the same and current rating but of different duty, subject any modification necessary to control, indication an interlocking circuitry. Whilst, as for circuit-breakers, closing mechanisr of either the dependent power solenoid or stored er ergy spring types are acceptable, manufacturers to date have supplied only the former. Compared with circuit breakers, the power requirements of the closing solenoids of fused switching devices are relatively modest — of the order of a few kilowatts. To meet CEGB operational and performance requirements, the design philosophy of fused switching device equipment follows more closely the principles of circuit-breaker switchgear than that of contactor controlgear. Indeed, interrupters of the air-break type are virtually circuit-breakers, but of limited short-circuit capability. Thus, closing mechanisms are of the 'latch closed' type and comply generally with the requirements specified for those of circuit-breakers. 5.2.4 Switching device operating mechanisms
Closing mechanisms of the dependent power solenoid type are specified to be 'trip-free'. Alternatively, if not trip-free in the generally accepted sense, they must simulate the action by being free to allow opening of the switching device immediately after closure, regardless of whether the closing control circuit remains energised. Stored energy mechanisms must comply generally with the requirements specified for circuit-breakers. 5.2.5 Main circuit fuselinks
Operation of any fuselink initiates opening of the switching device. This is essential in order to preserve the integrity of the `on/off indication and hence, as far as possible, indication of the state of the plant controlled. The fuselinks for the short-circuit protection of the main circuit are of the HBC type compliant with BS2692. The rating of the fuselinks fitted is normally the highest which will provide satisfactory 'take-over' from the switching device. Virtually all 3.3 kV motors are switched at full system voltage, i.e., direct-on-line started. Thus the switchgear must be capable of making and carrying, until the drive has run-up to operational speed, a current of several times that of the motor rated full-load. Thus, the maximum rating of motor which may be controlled by fused switching device equipment is determined by the overcurrent carrying capability of the fuselinks of the highest rating permissible in the switchgear. The highest rating of transformer which may be so controlled, however, is dictated more by the rated continuous current carrying capacity of the fuselinks,
Low voltage switchgear, controlgear and fusegear takine into account 'inrush' upon switching in. The ina\imum rating of fuselink i s, of course, determined hv the overcurrent making and breaking capability i• die switching device. The principle of co-ordination o he performance of the switching device with that fuselinks is described in Section 5.1 of this o f the j l arter. The fuselinks are mounted on the carriage of the device, on the busbar side, such that they .%%itching automatically from both the busbars are disconnected nJ he circuit when the switching device is discon.inected (isolated). It is possible to gain access to the (tiselinks only when the switching device is disconnected. To ensure opening of the switching device automatically upon operation of any fuselink, each fuseincorporates a striker pin arranged to actuate the li nk ;ppine mechanism directly or through energisation ;; of the [rip circuit by an auxiliary switch. Flag indica[ion of the operation of the fuselinks is provided at he s‘kitchgear. Examples of switchboards featuring !ii,e(.1 equipment are shown in Figs 5.46, 5.47 and 5.48. [
6 Low voltage switchgear, controlgear and fusegear 6.1 Required performance he principal low voltage auxiliaries plant supply
in power stations in the UK operate at 415 V, three-phase for motor drives and three-phase and neutral where single-phase supplies are required. The three-phase short-circuit level of these systems, the neutral point of which is normally solidly earthed, can approach 43 kA. To satisfy the system conditions, the .viitchilear is rated as follows.
6.1.1
Short-circuit withstand strength of busbar
systems 36 kA (equivalent to 26 MVA) or 43.3 kA (equialent to 31 MVA), as appropriate, for 3 s, when the busbar protective device, i.e., feeder circuit, is i:ircuit-breaker. \\ here the busbar protective device features fuses, 36 L,\ or 43.3 kA 'prospective', as limited in ina2nitude and duration by the 'cut-off' characicristic of the fuses.
I he peak v alue of the major loop (of current) during firq c,■ cle of current is taken to assume a magilitthie of not less than 2.3 times the symmetrical value, i.e., 2.3 x 36 kA or 2.3 x 43.3 kA, dppropriate. It will be appreciated that whilst in his peak is actually attained, it is usually a 'pro-
e Nalue in (b), reduced markedly by the cut-
011 characteristic of fuses at currents of short-circuit el.
6.1.2 Capability required of main circuit making/breaking devices (a) Circuit-breakers
• Rated short-circuit breaking current: Symmetrical — 36 kA or 43.3 kA, as required. 0
Asymmetrical — as symmetrical value plus 50 0 DC component. • Rated short-circuit making current: a current equivalent to 2.3 times the value of the rated short-circuit (symmetrical) breaking current, i.e., 2.3 x 36 kA, or 2.3 x 43.3 kA, as appropriate. • Short-time current capability: a current equivalent to the rated symmetrical breaking current for a duration of 3 s. (b) Contactors Contactors switching main circuits, e.g., motor circuits, are selected as follows,in accordance with the 'duties' and 'utilisation categories' recognised in BS5424: Part 1: • Direct-to-line started motors other than actuator drives
Rated duty — uninterrupted. A duty in which the main contacts may remain closed whilst carrying a steady current without interruption for periods of more than eight hours (weeks, months, or even years). Utilisation category — AC3, but AC4 if 'inching' or 'plugging' is a feature of the duty. AC3 is appropriate where the normal duty is the starting of a motor direct-on-line, and its switching off under normal running load. 'Plugging' is a term used to denote stopping or reversing a motor rapidly by reversal of the motor primary connections while it is running. 'Inching' implies energising a motor once or repeatedly for short periods to obtain small movements of the driven mechanism. Mechanical endurance — 1 million no-load operating cycles. This represents the number of no-load operating cycles which can be made before it becomes necessary to service or replace any parts other than contacts. • Actuator drives
(excluding modulating duty). Rated duty — intermittent duty Class 0.1, onload factor 60%. A duty in which the main contacts of a contactor remain closed for periods bearing a finite relationship to the no-load periods, both periods being too short to allow the contactor to reach thermal equilibrium. The intermittent duty above implies a capability of operation at a rate of 12 operating cycles per hour, the on-load period of each cycle being 60% of the whole cycle. 391
Chapter 5
Switchgear and controlgear
F.yropp a BOURNE'
33.y UNIT AuXIL APP BOAR 00.
0
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3 33/v UNIT SERVICES TRANSFORMER
350A TYPE AK CONTROL GEAR
350A TYPE AK CONTROL GEAR
350A TYPE AK CONTROL GEAR
350A TYPE AK CONTROL GEAR
350A TYPE AK CONTROL GEAR
I 1 .
ISUOA TYPE A. . CIRCUIT BREAKER I
1 ' DOOR SYMBOL ' COLOUR WHITE
, 603A TYPE AH• CIRCUIT BREAKER
DOOR SYMBOL COLOUR SIGNAL RED
CONDENSATE 0 EXTRACTION PUMP A
DC HEATER 0 EXTRACTION PUB , A
DOOR SYMBOL COLOUR BRILLIANT GREEN
DOOR SYMBOL COLOUR ORANGE
A
V
START UP AIR PUMP B
DOOR SYMBOL COLOUR WHITE
GAS RECYCLING FAN A
0
DC HEATER EXTRACTION PUMP B
DOOR SYMBOL COLOUR COLOUR WHITE
DOOR SYMBOL COLOUR FRENCH BLUE
:Fr
LU CC
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rcsi. ,,. : R° "
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0
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DOOR SYMBOL COLOUR BLACK
0
FUEL OIL PIMP
DOOR SYMBOL COLOUR SIGNAL RED
ACB
B
GAS RECYCLING FAN
• 0 30.1 CONDENSATE MAKEUP PUMP
000R symeoL COLOUR BRIU_IANT GREEN
DOOR SYMBOL COLOUR MIDDLE BROWN
Sly
SCE VIEW OF CIRCUIT BREAKER PANEL
SIDE VIEW OF CONTROL GEAR PANEL REL AY BE.
ACCESS TO FUSE TERMINAL CHAMBER BuSBAR CHAMBER
Top TER sv•ATCR NO DE VICE COWART -MEW.
ACCESS TO FUSE A TERMINAL CHAMBER
CT
cHAmBER CABLE BOX BuSBAR CHAMBER BOTTCm TLER SWITCH.NG DELICT COMPARTMENT
CT cHANIBER CABLE Sox
FIG.
392
5.46 3.3 kV switchboard featuring Whipp and Bourne Type AK fused equipments arranged in double-tier formation
Low voltage switchgear, controlgear and fusegear manently. Type c co-ordination requires that no damage (including permanent alteration of the characteristics of any overload relay) shall occur. However, light burning of contacts, and risk of their welding — the latter provided that no flashover occurs — is accepted.
6.2 Design and construction 6.2.1 General
This section describes the design and construction of the switchgear, controlgear and fusegear found on the 415 V and lower voltage systems. The requirements outlined are those for equipment concerned directly with the control of operational plant. They are not necessarily applied in non-operational plant areas, e.g., offices, welfare blocks, stores, etc. Henceforth in the text, the switchgear, controlgear and fusegear will be referred to simply as the switchgear, In AC applications, the switchgear is classified into two duty classes commensurate with the severity of the system conditions. These duty classes are: FIG. 5.47 3.3 kV fused units of Whipp and Bourne manufacture, generally as depicted in Fig 5.46 but Shown withdrawn and tilted for inspection/maintenance. The left hand unit features a vacuum switching device and that on the right an air-break interrupter.
Utilisation category
— AC4.
Mechanical endurance — 1 million no-load operating cycles.
• Substantially non-inductive loads switched on for long periods Rated duty — uninterrupted. Utilisation category — AC1 Mechanical endurance — 0.3 million no-load operating cycles. Additionally, contactors shall be capable of making tt nd carrying the specified prospective short-circuit current of the system, as limited in magnitude and duration by the associated circuit short-circuit protective device, i.e., fuselinks. The co-ordination between the contactor and the circuit short-circuit protective device, in accordance oith 13S4941: Part 1: Appendix C, is basically as follows: • Type b co-ordination for equipment utilising overload devices to BS4941: Part 1. • Type c co-ordination for equipment utilising overload relays to BS142. Type b co-ordination accepts that the characteristics of any overload relay may be altered per-
Duty Class I For use in systems where the power factor of short-circuit current is extremely low, e.g., where the switchgear is connected in relatively close proximity to the source of generation. Duty Class 1 is the normal requirement. Duty Class 2 For use in 'distribution' systems in which the power factor of short-circuit is not likely to be lower than 0.3. Mostly the switchgear is arranged in multi-circuit switchboard formations accommodated in purpose built switchrooms. However, it is expedient in certain instances to locate items, such as small motor starters and distribution fuseboards, local to the plant involved. Except in the case of distribution fuseboards, although there is now a tendency towards grouping starters into small multi-motor control centre formations, the requirement 'local to plant' is largely for single-circuit units — floor standing or wall mounted. Main switchboards, i.e., unit and station auxiliaries switchboards, usually comprise a combination of circuit-breakers, fused motor starters and fused distribution gear. The incoming supply circuits of such switchboards are almost always circuit-breakers. In many cases the supply to the switchboard is derived from a 3.3 kV/415 V transformer housed in the switchboard — the high voltage feed being by cable connected directly to the transformer HV terminals. The switchgear includes all protective and interposing relays, main and any necessary interposing current trans- . formers, transducers, instruments, control, selector and test switches. 393
Switchgear and controlgear
Chapter 5
ItG, 5.48 3.3 kV switchboard of Reyrolle manufacture. The three left hand units are 'fused equipments Class Sl4A' and the three right hand units are 'air circuit-breakers Class SA'. (see also colour photograph between pp 496 and 497)
The general assembly of the switchgear complies with BS5486: Low voltage switchgear and controlgear assemblies: Part 1, Specification for type-tested and partially type-tested assemblies (general requirements): ■thich is identical with IEC Publication 439-1: 1985. 394
However, for power station service it is necessary to augment and interpret the British Standard as outlined below. Representative switchboard formations are shown in Figs 5.49 to 5.51. Typical examples of the individual cubicle arrangements, air circuit-breakers
Low voltage switchgear, controlgear and fusegear
395
Switchgear and controlgear
Chapter 5
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BLPTC SOOTBLOwER AIR C OM PRE S SOB MOTOR HEATER 2
0
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A
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0 YELLOW 4155 CHIMNEY SERVICES BOARD SECTION 2
0 RED raTvOC CONTROL BATTERY CUBICLE
0 BROWN LISA AUX BOIL ERHOUSE BOARD, CHIAINEr PLANT BOARD 2 FEEDER
A YELLOW LIST CHIMNEy PLANT BOARD I NTERCONNECTOR
0 RED SOOTEILOWER AIR Comp R ESSOR SF STAGE LAB OIL ROAR A
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ORANGE SERVICES DISTRIBUTION &NAPO 2
0 WHITE SOOTTILOwER AIR COMPRESSOR ST STAGE LUB OIL PUMPS
IL
SLUE SOOTBLO.ER AIR COMPRESSOR COOL NO WATER PUMP 5
VSROwN C. BLACK SOCRIILOWR SPARE AIR COMPRESSOR IUN—ECUIPPED COOLING WATER PUMP A
ORANGE FLOODLIGHT TOWER II
vimiTE CHIMNEY WASH CRAIN PUMP
BLACK MISCALL ANECTUS TRACE HEATING SECTION 2
V BLUE 249VAC CUBICLE HEATERS I TV AC. DC TEAT SUPPLIES
FIG. 5.50 Typical 415 V switchboard of Electric Construction Co manufacture
and starter equipment that comprise the switchboard formations are illustrated in Figs 5.52 to 5.54. Basically, switchgear arranged in switchboards is of Form 4 to BS5486. The 'Form' of construction determines the degree of separation by barriers and partitions (within the switchgear structure) of the major components. 'Form 4' specifies the separation of busbars from the functional units, and separation of all functional units, including their outgoing terminals, one from the other. Essentially, the whole of the busbar system up to the point of connection to the short-circuit protective devices of each circuit must be capable of withstanding a short-circuit at any point other than in the immediate vicinity of the short-circuit. There of course, be damage from arcing at the point of short-circuit. Also, the whole switchboard assembly must withstand any external fault. In the event of an internal arcing fault on any functional unit, the damage 396
must, as far as possible, be confined to that unit, so
that the busbars and all other functional units remain fit for service. In addition to the basic requirements of BS5486, specialised equipment and components, e.g., circuit-breakers, contactors, fuse-switches, etc., must comply with the appropriate British Standard. Withdrawable and removable parts (see Definitions in BS5486) of the same manufacture, type, rating and duty must be interchangeable. Withdrawable and removable parts of the same manufacture, type and rating, but of different circuit duty must be interchangeable, subject to any necessary modification to auxiliary circuits, protective devices, etc. Handling equipment, e.g., lifting devices, is provided for withdrawable and removable parts exceeding 25 kg gross weight. The use of hygroscopic or flammable materials is avoided as far as practicable. Terminals in which a
FIG. 5.51 Typical 415 V swifchboarcl of Flo:fro-Mechanical l`vialinfacitiring Co mantilaotfie (see also colour photograph heiwceu pp 496 and 497)
Low voltageswitchgear, controlgear and fusegear
co
JeabloJluop pue .leaEqi!Aiss
CUBICLE VENT
TOP APERTURE COVER
CONTROL FUSES AND LINKS VOLTMETER SWITCH
v
I e —Q
—LOCKING HASP ----
NEUTRAL BUSBAR
LOCAL CONTROL SWITCH
PARALLELING CONNECTIONS
LOCAL REMOTE SELECTOR SWITCH
i NTERTRIP RECEIVE — RELAY —TYPE VAJY13
P V.C.GA$BAEFLE
RESTRICTIVE EARTH FAULT RELAY — TYPE CAG 14
ARC CHUTES
BUCHHOLZ RELAY—TYPE VAAll
DOOR HANDLE
BUSBARS NEUTRAL LINK NEUTRAL/EARTH CONNECTION AND NEUTRAL CABLE RISERS
CLOSING MECH. AIR CIRCUIT BREAKER
BUSBAR CHAMBER BARRIER
SHUTTER LOCKING 270V D.C. MONITOR LAY — TYPE VAA11
CABLE SIDE CONNECTIONS
I
AUTO TRIP FLAG I NDICATION RELAY — TYPE VA F
CABLE SIDE NEUTRAL CONNECTIONS
il
HEATER I NDICATION
MASTER TRIP RELAY —TYPE VAJY11
ftva
LAMP (BLUE) -
STANDBY EARTH FAULT RELAY — TYPE COG 14
HEATER SWITCH HEATER LINK
MAIN CABLE GLAND PLATES (BOTTOM ENTRY)
HEATER FUSE TRIP SUPERVISORY RELAY — TYPE VAX 31
EARTH CONNECTIONS
SHUTTER LOCKING LEVERS SHUTTER FRONT VIEW
SIDE VIEW
FIG. 5.52 GEC type N.1180 415 V air cireidl-bri,iaker cubicle, used iypically :is switchboard incoming, interconticciing and bosbar-sectioning equipmeni
REAR VIEW
Low voltage switchgear, controlgear and fusegear
ARC CHUTES POSITION INDICATOR OPERATION COUNTER
ARCING CONTACTS MOVING CONTACTS FIXED CONTACTS
ISOLATING CONTACTS
SLIDE RAIL
AUXILIARY SWITCHES ER RACKING MECH COVER PLATE
REAK
MANUAL TRIP BUTTON LOCKING FLAP LOCKING BOLT
MANUAL CLOSING MECH COVER PLATE VENTILATION GRILL
FIG.
H
FRONT PLATE
5.53 DEC type M80 circuit-breaker shown withdrawn from cubicle 399
Switchgear and controlgear
Ch
VIEW INSIDE TOP COMPARTMENT
D ROPP E R COMPARTMENT
FUSE SWITCH
L--7
1
•
AUML;ARY SWITD•1
CONTACTOR
ANINIE7ER CT 40/1
OVERLOAD RELAY
I NTERPOSING RELAYS
TEST SWITCH
TRANSFORMER 415/110V
Flu. 5.54 Typical interior of a motor control unit fitted to the type of switchboard illustrated in Fig 5.50
screw compresses a bare wire conductor directly are not permitted. Whilst, in general, no diversity factor is allowed for Duty Class 1 equipment, the provisions of BS5486: Part 1 in this respect are accepted for Duty Class 2. As for switchgear at the other voltages, the temperature rise of terminals for external cabling must not, when carrying rated operational current continuously, exceed 50 ° C, or the limits specified in the appropriate 400
apparatus specification, whichever is the lower. All main conductors and incoming/outgoing terminals must be identified with their phase/polarity colours, presently in accordance with BS158. The colours at the various points of identification must be of durable material and a minimum of 300 mm 2 in area. Because in the course of time the adhesive may fail; thus allowing 'unwinding' and introducing the risk of fault, identification by taping is not accepted.
Low voltage switchgear, controlgear and fusegear closures 0,2 1 ti,..lo‘tires. unless specified or approved otherwise, are ii:ctal. ventilated naturally, and provide a degree of to 13S5400 as follows: Oil
,I mpinent for
•
indoor use — Code IP31.
,luirineni for outdoor use — Code IP44, or of 'first' and 'second' numeral as necessary.
•
.2!Icr
ichgear featuring withdrawable parts, the spedciirce of protection must obtain whether the , the connected or disconnected posiis in . „„ T ment be independent of the fitting of closing .i nd must arrangements at the point of ' other sealing or cabling. Unless the specified degree if external
provi cled by the enclosure is maintained \ample, shutters or shrouding, temporary or c are supplied for use when withdrawable or re- ,, He parts are removed. Such covers have captive iries and padlocking facilities. \,.liiicionallv, all enclosures must provide: rrotectiOn
• \,L cqu aie support of withdrawable parts during with-
,h- ,ok al, and when left in the disconnected position.
po,iti‘e restraint of a withdrawable part at the limit the means adopted must require delimanual manipulation before it •is possible to rite , engage the withdrawable part from the enclosure. Ji
•
• \.ces to main and auxiliary contacts from the front of he equipment. Access to fuses in control and Luixiliarv circuitry, relays, instruments, etc., is nortalk from the front of the equipment in the case ol L'ontactor controlgear, but usually from the rear , , t) circuit-breaker equipment. or work in safety on the de-energised side of any .11,111) circuit isolating device with adjacent main live. This is a most essential requirement Ls rarely possible, other than during planned , htitLlov. n , in the more important switchboards to mak,: dead circuits other than those requiring par-
• In the case of outdoor equipment, any fixings which of necessity pierce the Walls of the enclosure for the attachment of external fittings must be- gasketted. Exceptions to this rule are the fixings of labels. These may penetrate the walls of the enclosure provided that they do not exceed 5 mm diameter and are effectively sealed. Fixings for the attachment of outdoor enclosures to supporting structures must not pierce the walls of the enclosure. To protect persons against electric shock, the provisions of protection by barriers or enclosures, protection by insulation of live parts and protection by using protective circuits, specified in BS5486: Part 1, are followed. Particular requirements with respect to doors and covers are: • Hinged doors shall open not less than 90 0 but, in so doing, the movement must be limited to prevent damage to equipment mounted on the doors, and also damage, or the application of tension, to wiring connecting equipment on doors to that in the static part of the enclosure. • All indications must be clearly visible when doors are closed, and the equipment available for service. Additionally, to assist in the prevention of unauthorised interference with the intended functioning of the equipment, provision is made for padlocking all doors closed. • Doors and covers which give access to parts live at main circuit voltage are secured by fastenings, e.g., screws and nuts, the release of which necessitates the use of tools. Fastenings intended primarily for operation by coins are not acceptable in this context.
• I
auenticm Iso, any main circuit parts which :1L.o remain fix lieu access has been gained to the :merior of an cii,loure, other than through doors ki ■ cr-, secured by fastenings necessitating the tools, must be further enclosed to prevent LLdeIttaI touching by persons. The aim in such cases lo achieve a degree of protection of not less than I 1);() (co 13S5490), Where it is physically impossible :0 meet this requirement in respect of the contact .. Tries of the larger sizes of fuse-switch and fuse t he openings must be as small as practicable Li.,inutaciuring tolerances will allow; additionally, tna ■ be deemed necessary to fit 'obstacles' to slruct access by hands/fingers.
As far as is practicable, bus wiring is segregated from all other wiring and run in ducting, conduit, etc., preferably metallic. Largely from considerations of mechanical security, the minimum permissible crosssectional area of bus wiring is 2.5 mm 2 . To facilitate efficient operation of the switchgear, the following dimensional limits above operating floor level are observed wherever possible:
,
.
• f or a
cce ss to main circuit fuselinks only when they
,ire dead.
Overall height
2600 mm (max)
Operating handles — (highest and lowest positions reached by an operator's hand), protective relays, instruments and mechanical indicators
2000 mm (max), 450 mm (min)
Doors and panel handles/locks
2000 mm (max), 300 mm (min)
To promote a movement of air through the switchgear that is sufficient to prevent condensation when it is out of service, heaters of the metalclad black heat pattern are provided within the enclosures. 401
Ch
Switchgear and controlgear 6.2.3 Cabling arrangements
Wherever practicable, external cabling is arranged to enter equipment from below. To allow some freedom of choice as to the type of cabling used in a particular circumstance, main circuit terminals must be suitable for the reception of conductors of either copper or aluminium, and arranged to minimise the bending of t he cores. The main circuit terminals of each functional unit in a switchboard are enclosed separately in an air insulated compartment or barriered section/subsection of earthed metal or approved insulation material. Such a compartment may also accommodate current transformers for instrument and protection purposes. Terminals for the connection of external control and auxiliary circuits are grouped and positioned relative to the main circuit with which they are associated. Whilst not necessarily so in the past, it is in most cases now policy to enclose each group separately, and thus reduce the risk of work or a fault on one group jeopardising another. Ali terminal arrangements must, with cables connected, ensure achievement of the clearances and creepage distances shown in Tables 5.1 and 5.2. TABLE 5.1 Indoor equipment
hquipmeni
Duty Class Duly Class 2
Minimum clearance in air between phases and from phase to earth, mm
Minimum creepage, mm CTI less than 200
CTI 200 or greater
19
25
19
19
19
19
TABLE 5.2 Outdoor equipment
Equipment Duty Clases 1 and 2
Minimum clearance in air, mm
Idetv,een phases Phase to earth
Minimum creepage, mm CTI less than 200
CTI 200 or greater
25
38
25
25
25
25
The physical disposition of main circuit cabling relative to auxiliary cabling at the point of entry into the equipment enclosure is arranged to minimise the risk of fault or fire on the former affecting the proper f unction of the latter. For this reason, where the design of equipment necessitates the installation of lengths of both main and auxiliary incoming/outgoing cabling within the enclosure, the former is segregated from the latter by earthed metal or other mechanically robust 402
fire-resistant material. Cable armour alone is not cepted as satisfying this requirement. Terminal boxes and gland plates for single-core L. bles rated in excess of 400 A are required to be designe, specifically to minimise the production of inducet., currents. Gland plates are supplied on the basis of one plat per cable gland, and must be detachable to facilitate drilling to suit by the cable contractor. Insulation must be so mounted and the method of attachment of connections thereto such as to minimise the likelihood of mechanical overstressing during normal tightening of the mounting and connection fixings. Particular care is taken to ensure that expansion and contraction of components shall have no damaging effect, having especial regard to the temperatures likely to be attained under fault conditions. Additionally, the configuration of the surfaces of insulation must be designed to minimise the accumulation of airborne pollutants. 6.2.4 Electrical clearances and creepage distances
As a general rule, the electrical clearances and creepage distances shown in Tables 5.1 and 5.2 are observed as minima. However, some relaxation is permitted specifically in the following areas: • Contactors and associated overload protective devices may have clearances and creepage distances not less than those specified in BS5424: Part 1: Appendix B. • Circuit disconnectors (isolating devices), fuse-switches, switched and other disconnectors may have clearances not less than 12.5 mm. The relaxed dimensions may be maintained on connections to the terminals of these components for a distance not exceeding 40 mm. The clearances shown must be maintained irrespective of any insulation applied, unless such insulation is capable of withstanding the full power frequency high voltage test. 6.2.5 Busbar systems
The busbar circuit of a switchboard comprises the complete conductor system up to its points of connection to the circuit disconnecting/protective devices of the functional units. Typical busbar circuits are illustrated in Fig 5.55. Main and tee-off busbars are contained in separate compartments within the switchboard. They are usually air-insulated, but may feature solid insulation at the option of the manufacturer. Where insulation is other than by air, it must be in the form of sleeving with joints encased in moulded or similar covering. Because of the possibility of deterioration with age,
Low voltage switchgear, controlgear and fusegear
CiFICuiT PROTECTIVE DEVICE
EE-OFF BJSEARS
neutral current, for example, where the load is wholly or predominantly fluorescent lighting, the neutral is assigned a rating equivalent to that of the phase conductors. Except in the case of orifices (spouts) protected by shutters, e.g., at disconnecting (isolating) contacts, access to busbar circuits may be gained only by the removal of covers secured by fastenings requiring the use of tools, e.g., spanners, screwdrivers, to release. Each cover must be clearly and indelibly marked BUSBARS in red. Shutters protecting orifices are provided
with facilities for padlocking closed — for use (for example) when a withdrawable part is removed. The short-circuit withstand strength of busbar systems is described in Section 6.1 of this chapter. However, for the lower circuit (functional unit) current ratings, it is often necessary to reduce the crosssectional area of the tee-off busbars at the point of attachment to the terminals of the circuit short-circuit
CIRCUIT PROTECTIVE DE ViCE
TEE OFF BUSRARS
MAN 8USBASS
BuSRAP RCTECTIvE DEVICE
I
I
It..
5_55 Typical busbar circuits
. 'iirminilinsz' through loss of adhesion, taping of t1 toriN not accepted for any purpose. I IL iNko husbar circuits in busbar sectioning/interequipments must be segregated from each by carthed metal or approved fire-resistant in-
For withdrawable equipment, the segregation [.. quired io extend up to, and including, the fixed ... oluicciinu contacts. This segregation is necessary rcrruit \k ork anywhere on one set of bars whilst ,!iler remains live provided the busbar sectioning opc n . .11low freedom in the positioning of circuits in ri aboard, busbars are specified to have a con. 'lii rating throughout their length; such re qui rement k1, of value should extension become necessary. general rule, neutral conductors are required current carrying capability of not less than holf that of the associated phase conductor. How%t here the connected
loads result in abnormal
protective device, to dimensions compatible with those terminals. To maintain, as far as practicable, the security of the busbar system at this point, such reduction in section must not extend for a distance exceeding 40 mm from the terminals of the protective device unless the conductors are insulated for the rated insulation voltage, and supported in a mechanically robust manner. Where so insulated and supported, the occurrence of short-circuit earth faults is unlikely. Main circuit fuselinks are to BS88 and of the general purpose or motor circuit type, as appropriate. Similarly, fuse holders are to BS88. However, having regard to the 1 2 t let-through of large fuse-links at high prospective fault currents, the maximum rating allowed mounted in fuse holders is 100 A. Fuselinks rated above 100 A are mounted in fuse switches or similar devices.
6.2.6 Earthing of structures Each switchboard i provided with a main earth bar (protective conductor), usually and preferably on the outside of the enclosure, extending throughout the length of the switchboard. Subsidiary (tee-off) bars are provided as necessary. The bars may be of copper, aluminium or aluminium alloy. To facilitate the attachment on site of earth bonding cables, a clearance of not less than 15 mm is provided between the back face of the main earth bar and the adjacent surface of the switchgear enclosure. All joints are bolted. Because of problems at the interface of aluminium cable lugs bolted directly to tinned copper surfaces, bars are plain finish, i.e., untinned. Joints in aluminium bars have the oxide film removed by steel wire brush; the surfaces so cleaned are then coated with petroleum jelly or other approved compound immediately before assembly. For outdoor installations, the completed joint is sealed by the application of an overall coating. Provision is made at each end of each main earth bar for connection to the station main earthing system. To assist achievement of 403
Switchgear and controlgear
Chapter 5
a satisfactory connection, a flat area of not less than 50 x 50 mm must be provided. Earth bars of copper are dimensioned as shown in Table 5.3.
(f) To prevent connection to the supply of main Circui t parts to which access has been gained as in (e). However, whilst a defeat feature is provided fo r use when the door is open, it is not possible to
TABLE 5.3 Copper earth bar dimensions
Subsidiar y (tee-off) earth bar
Main earth bar Busbar system short-circuit protection
Crosssectional 2 area, mm
Minimum width, mm
Crosssectional area, mm 2
Minimum width, mm
Fuse
150
25
75
25
Circuit-breaker (3 s rated)
300
50
150
25
Earth bars of aluminium alloy must have a width not less than that required for copper, and possess electrical and mechanical properties not inferior to those of copper. Single main circuit equipments are provided with an earth terminal. Withdrawable parts are, when in the connected position, bonded to the equipment earth bar or terminal through contacts designed specifically for the purpose. Such contacts must establish the earth connection before the contacts of the main circuit connect. The neutral points of transformers are earthed at the switchgear through removable links. 6.2.7 Mechanical interlocks
Mechanical interlocking is of the preventive type, i.e., designed to prevent as opposed to correct an improper action, and effective as close as practicable to the point at which force is applied. Essentially, such interlocks are provided: (a) To prevent the closure of a switching device incorporated in a withdrawable part, unless the withdrawable part is located correctly in the connected, disconnected or, where appropriate, test position. (b) To prevent the opening or closing of 'off-load' disconnecting (isolating) devices unless the associated switching device is open. (c) To prevent the simultaneous closure of 'forward' and 'reverse' or 'low speed' and 'high speed' contactors. (d) To prevent the simultaneous closure of both contactors or both switches of a changeover arrangement. (e) To prevent access to main circuit parts through doors unless such parts have been isolated from all sources of supply. 404
close the door unless the interlock is restored. Pro , vision is made for padlocking the interlock against defeat. Additionally, where for reasons of safety it is essential to prevent the inadvertent starting of a drive by closure of the circuit isolating device in the presence of a welded contactor. (g) To prevent the closure of the disconnecting (isola-
ting) device in motor starters unless the associated contactor is open. 6.2.8 Coded-key devices
Coded-key operated devices are provided where necessary in a scheme of system interlocking whereby: • A key, when inserted, permits a circuit-breaker (or other switching device) to be closed, and is free only when the circuit-breaker is open. Attempted removal of the key when the circuit-breaker is closed must not cause tripping of the circuit-breaker. • A key is free only when a circuit-breaker is removed from the connected position. It must not be possible to place the circuit-breaker in the connected position with the key removed, but it is possible to place and operate the circuit-breaker in the disconnected position. 6.2.9 Protective systems components
Each component of the protective system, e.g., current transformers, relays, etc., must be capable of withstanding, without damage, the passage of the shortcircuit currents available from the busbars for the short-time rating of the equipment or, in the case of fuse protected equipment, be capable of withstanding
Low voltage switchgear, controlgear and fusegear
The let-through current of the highest rated fuselink hiJi may be fitted in the associated main circuit. ,■ 6 2 10 Current transformers normally fitted on the side of rrcnut transformers dre 0.5itching device remote from the busbars. secondary ‘vindings of each single-phase current nic and the star-point of the secondary windof each three-phase group are normally earthed :one point only through a removable link. Where not readily visible, e.g., in circuit(ratisformers are duplicates of the rating plate are kcr in a more convenient position. Ammeters and voltmeters
6.2.11
Vninelers and voltmeters mounted on the switchgear flush type. Ammeter scales ,, r c of the back-connected, full-load current produces approxi, e ,c.) chosen that TJ;ek 75tro full scale deflection. \\ here there is no requirement for indication at a
... mote point, those at the switchgear may be conin circuits of ratings up to the order ced . , t to A.
be capable of carrying rated ..irrent continuously, be suitable for use with directHe started motors where appropriate and able to .,, t ih,tand without damage the passage of fault current he operation of the main circuit protection. All ammeters Must
6 2.12 Control switches on(roI switches for circuit-breakers are of the pistol..:r!p (rotary) type; for contactor gear, pushbuttons ire the norm. Facilities are provided for padlocking !,11- ■ selector devices in all positions, and rotary condevices in the neutral position. Pushbuttons are and coloured in accordance with Table 5.4.
Mo./dm/toil inscriptions and colour coding
1
._ mtlir
tioual motor
1- Slai2 motor
1,ike or damper
F. nicrgency Slop
Inscription
Colour
Start Stop
Green Red
Forward Reverse Stop
Green Green Red
Open Close Stop
Black Black Red
Stop
Red
" t,tri.
buttons are placed to the right of or above ':op buttons. Control devices are located to the right ,! or below selector switches.
6.2.13 Fuses
Fuselinks in both main (i.e., power) and control/ auxiliary circuits are of the cartridge type.
Main circuit fuselinks are to B588 and of the general purpose or motor circuit type, as appropriate. Control/auxiliary circuit fuselinks may be to BS88 or to Defence Standard DEF 59-96: Part 1. Fuseholders are to BS88 or DEF 59-100: Part 1, as appropriate. Fuses in control/auxiliary circuits are grouped to assist circuit identification and to provide convenient points of isolation. Wherever practicable, fuses to BS88 are used in preference to the DEF type. The preference stems largely from the provision in BS88 holders of better shrouding of the contacts and a generally greater suitability for use as points of isolation. 6.2.14 Circuit-breaker equipments
Circuit-breakers are specified basically to B54752: Part 1, but with the following additional capabilities: • A rated asymmetrical breaking current equivalent to the rated symmetrical breaking current plus, in one phase at the instant of contact separation, a DC component of not less than 50 07o of the AC component in that phase (see Fig 5.24). • Breaking a current equivalent to 100% of the sym-
metrical breaking current applied to an outer pole, without the unbalance forces produced under these conditions adversely affecting correct operation. Where required for a triple-pole and neutral installation, the neutral connection is established through a bolted link. Circuit-breaker operating mechanisms are of the de-
TABLE 5.4
Duty
For the purpose of identification, switchboards, circuits, control equipment, etc., are provided with labelling and coloured symbols largely in line with the requirements specified for 3.3 kV and 11 kV switchgear.
pendent power solenoid or stored-energy motor chargedspring type, complying basically with the requirements outlined for 3.3 kV and 11 kV equipment. Whilst both types are equally acceptable from the point of view of performance, the latter, although of somewhat greater complication constructionally, does not require the provision of a relatively heavy DC closing supply. Thus, this mechanism can be of advantage in installations where the provision of a heavy battery Source of supply could present a problem — technically and/or economically. In basic concept, all low voltage switchgear assemblies incorporating circuit-breakers are of the metalclad type in accordance with the definition of the term `rnetalclad' outlined for 3.3 kV and 11 kV equipment. Thus, disconnection (isolation) facilities for main and auxiliary circuits, and also the provision of shutter gear protecting busbar and circuit contacts (spouts) 405
Chapter 5
Switchgear and controlgear in the cubicle, follow the arrangements established for the higher voltage equipment. However, it may be helpful to recall that the requirement described in Section 1.3 of this chapter to the effect that work on current carrying parts is permitted only when such parts are earthed, is pertinent only at high voltage. Accordingly, no provision is made for the deliberate earthing of current carrying parts of low voltage equipment.
each circuit comprises a contactor in association with high breaking capacity (HBC) fuselinks, together with means for disconnecting the main and auxiliary circuits from their respective incoming supplies. The basic arrangements recognised are as follows and depicted diagrammatically in Fig 5.56:
6.2.15 Contactor controlgear
Type 13
Motor circuits account for the bulk of the contactor type controlgear used in the power station. Essentially, P
0
Y
0
5
0
P
R 0
COM
Y 0
Cl=
0
CM=
B
• a Y 0 0
6
9-7,4A
Type A Non-withdrawable type with operational/ maintenance disconnection by fuse-switch. Withdrawable type having off-load plug and socket devices for maintenance disconnection and a switch within the fuse protected
N> - - TYPE A'
1=.
4
Com 0
—),
-ire
CM. L.. TYPE "El' --' ALTERNATIVE ARRANGEMENT
•
0—(1=
Y 0 •
0
-
I I l fl E -1
TYPE C'
- - TYPE '0
FUSES TO 5558 FOR TYPE C EQUIPMENT THE MAIN CIRCUIT FUSE LINKS ARE MOUNTED ELSEWHERE
FOR TYPED EQUIPMENT THE MAIN CIRCUIT FUSE L NKS MUST NOT EXCEED 100A RATING
FIG. 5.56
406
Alternative arrangements for contactor fuses and isolating devices
Low voltage switchgear, controlgear and fusegear zone for operational disconnection. The withdrawable assembly also accommodates the main circuit fuselinks. Non-withdrawable type with operational/ maintenance disconnection by a switch. Non-withdrawable type with a switch, within the fuse protected zone, for operational disconnection. pes A, B and C are equally acceptable. Type D is permitted only for fuse-fed switchboards. In Type D quipment, the fuses are mounted on the busbar side circuit disconnecting device. There is therefore, ', f the o he possibility that their replacement after operation t eould be attempted before the abnormality causing the operation has been corrected. The act of attempted -ement in such circumstances could initiate an L r eplacement arc at the fuse carrier/holder contacts. Restriction of the use of Type D equipment to fuse-fed switchboards, i.e., switchboards for which the busbar system is itself fuse-fed, is considered to reduce substantially anv risk arising from this cause. The several devices comprising the main circuit, e.g., the contactor, fuse-switch, etc., are usually manufactured by specialist component manufacturers and thus may have performance ratings against specific duties. Consequently , it is required that each 'circuit' cornprising a combination of disconnecting device, fuses, contactor, power terminals and associated internal connections be assigned a rated operating current by the manufacturer of the combination, i.e., the manufacturer of the circuit assembly. As in circuit-breaker equipment, any neutral links are of bolted type. As a general guideline and to allow for continet-teies, the circuit minimum rating for direct-to-line .larted motors is usually specified to be not less than 120 per cent of the nominal full load current of the motor. Filch fuse-switch and switch has a current making and breaking capacity not less than the value derived from I3S5424: Part Clause 4.3.5 when based on ilie assigned rated current of the circuit. In addition, •th..1) switches must be capable of making a current cninsalent to the supply source prospective short...tr am current as limited in magnitude and duration hs the highest rated fuselink which is permissible in :hie circuit. Where connection to the source of supply, e.g., Imsbars, is by plug and socket contacts, apertures ing access to the supply side are shrouded or shutiered. Shutters must operate automatically on insertion ,iiid removal of the withdrawal assembly, and are Identified as in circuit-breaker equipment, albeit the iering is, of necessity, usually smaller. or the purpose of indication, if required at a point(s) remote from the switchgear, devices for op-
erational disconnection are provided with auxiliary switches driven positively in each direction. Largely to minimise the risk of operator mistake, particularly in an emergency, the operating handles of devices for operational disconnection are arranged uniformly to close the device with an upward movement. Handles operating in a plane parallel to the front of the 0 equipment have a full movement not exceeding 60 either side of the horizontal. Mechanisms are of the independent manual type. It must not be possible to leave an operating handle in an intermediate position. Padlocking facilities are provided as follows: • For locking the handles of devices for operational disconnection in the open position — it being possible to maintain such locking of the device against closure when access to the interior has been gained for maintenance purposes. • For locking withdrawable contactor equipment assemblies in the connected position. • For locking shutters in the closed position. When padlocked, the shutters prevent access to the fixed isolating contacts which they shroud. Whilst the shutters are locked closed, it must not be possible for the isolating contacts on the withdrawable part of the equipment to make contact with the shutters should an attempt be made to place it in the connected position. • For locking disconnection (isolation) devices of the withdrawable/removable type in the connected position. Each circuit is provided with a visual indicating device to show whether the contactor is 'open' or 'closed', which must be effective in both the 'circuit connected' and 'circuit disconnected' positions. The device may be either mechanically or electrically operated. The originating action must be driven positively in the direction of closing the main contacts and must not impede operation of the contactor. Alternatively, and usually in the case of separately-mounted (i.e., Type C) units, the indication may be by lamps. If so, lenses are white for ON, green for OFF, the green lens being placed to the right of, or above, the white lens. The white lens is identified by the legend 'ON'. Electrically operated devices other than indicator lights must adopt a non-definite indication on loss of an operating signal. Each contactor is provided with four normally open and four normally closed auxiliary contacts, except that for the electrically-held type below 40 A rating, two normally open and two normally closed contacts may be accepted in conjunction with a repeat relay. Auxiliary contacts are driven as follows: • Block type — positively driven in the direction of closing the main contacts, but may be springreturned to the open position. 407
Chapter 5
Switchgear and controlgear
Note: a 'block' type contactor is one in which the contact system is carried in an enveloping case of moulded insulation material. The moving contact assembly operates usually with a parallel motion in a horizontal plane. • Clapper type — positively driven in both directions.
Note: a 'clapper', or 'bar', type contactor is one in which moving contacts are carried on an insulated bar and engage with stationary contacts mounted (usually) on a flat base of insulation material. The trip circuit auxiliary switch on latched contactors must close before the main circuit contacts touch. Means are provided which: (a) On latched contactors de-energise the closing coil when the contactor has closed and latched. (b) On both electrically-held and latched contactors prevent reclosure in the event of failure to close, or automatic opening, whilst the closing signal is maintained. Each contactor is provided with facilities for maintenance testing the opening and closing operations of the contactor by the use of the pushbuttons mounted on the enclosure front. The arrangements are such that the testing can be carried out only when the contactor is disconnected from the busbars. Control circuits function at the following voltages: • Contactor closing mechanisms, 110 V AC nominal, derived from 415/110 V control circuit transformers. • Trip circuits (of latched contactors), 110 V DC nominal. Control circuit transformers are 415/110 V, noninherently short-circuit proof, to 8S3535, Section F, but having an earthed metallic interwinding screen. 'Non-inherently short-circuit proof' transformers will, if short-circuited at the output terminals, be damaged unless disconnected by an overcurrent device. Such transformers are well suited to the operation of solenoid mechanisms in that, provided the overcurrent protective device (e.g., a fuse) exhibits a suitable time/ current characteristic, advantage may be taken of the 'short-time' capability (of the transformer) to satisfy the relatively heavy transient (inrush) current taken by the solenoid coil at energisation. Duty for duty, a transformer 'inherently short-circuit proof' would need to be of appreciably higher rating. Fuselinks are fitted in both poles of the input connections to the transformer. These may be mounted either in a fuse-switch or in fuseholders. The output connections are protected by a fuselink in one pole and a solid link in the earthed pole. The non-fused output terminal of the secondary winding is connected to earth through a removable bolted link. 408
6.2.16 Fusegear Fusegear is used primarily to distribute supplies rather than control specific items of plant directly, e.g., t o provide supplies to the smaller switchboards, separately mounted motor starters, valve actuators, etc. An important aspect of this role is the provision inherently of short-circuit protection. Fusegear may be built into and thus form an integral part of multi-motor control switchboards; these may constitute switchboards consisting wholly of fuse gear, or may comprise single circuit feeding units. Where, in addition to circuit disconnection (isolation) a switching facility is required, fuse-switches are employed. Where there is no switching requirement, distribution fuseboards are used. Fuse switches are basically to BS5419, double-pole, three-pole or three-pole and neutral as necessary. Neutral links may be either bolted or switched. Where switched, the neutral connection must be established before the phases 'make', and 'broken' after the phases 'break'. To preserve uniformity with the manner of operation of the handles of devices for the disconnection of contactor controlgear, those for fuse-switches are arranged to close the switch with an upward movement. For handles operating with a rotary action in a plane parallel to the front of the equipment, the full movement of the handle shall not exceed 60 ° either side of the horizontal. Mechanisms are of the independent manual type. It must not be possible to leave the operating handle in an intermediate position.
Note: an independent manual mechanism is one in which manual energy is stored and released in one continuous operation, such that the speed and force of the operation are independent of the action of the operator. Mechanical indication of the operating positions of the switch handles is provided to show when the switch is ON or OFF. When necessary, fuse-switches have provision for operating auxiliary switches. Where fuse-switches are of the withdrawable type, any main circuit parts which may remain live and become exposed upon removal of the withdrawable assembly are shrouded or shuttered. Such shutters operate automatically on insertion and removal of the withdrawable assembly. Distribution fuseboards may be of the wall-mounted box pattern, of the free-standing cubicle type, or may, where expedient, be incorporated in 'main' switchboards. Padlocking facilities are provided for: • Locking fuse-switch handles in the open position. It must be possible to keep the fuse-switch locked against closure when access to the interior has been gained for maintenance purposes. Only in excep-
.
Fuses tional circumstances, e.g., where continuity of supply is an overriding consideration, is provision made for padlocking handles in the closed position.
14100m, APPIROX
-41
MAIN LABEL.
king shutters in the closed position. Whilst c oc • shutters are locked closed, it must not be possible ror the isolating contacts on the withdrawable part he equipment to make contact with the shutters of I should an attempt be made to place it in the conn,:cted position.
fuse-switches of the withdrawable/removable type in the connected position.
• Locking
In addition to the traditional switchboards described certain specialised formations/units have been earlier, do eloped. An example of such development is the .actuator power/control distribution board' for the ji N tribution of power and control supplies to actuajars, e.g., valve and damper actuators. The basic intent al the arrangement is:
ON
ON
OFF
OFF
215Ornm APPRO%
6.2.17 Specialised switchboards/units
• The provision from a single location of both power and control supplies.
• The provision of alternative/standby power supply via changeover switches.
• To facilitate the use of 'composite' cable, i.e., cable containing screened power cores, together with control cores, within an overall sheath. The equipment of the switchboards — the busbar
• tem, contactors, fuse-switches, control switches, caMimi facilities, etc. — is generally required to comply ith the design and performance requirements specified for the more traditional switchboards. Figure 5.57 depicts a typical arrangement. A complementary development, but usable in its own right, is the 'actuator disconnection box'. This comprises, in effect, a wall or steelwork mounted junction box serving as the interface between the station \ed' cabling and the flexible power and control leads I rom the actuator. The connection to the box is established through plugs and sockets. The plug and socket concept serves the dual role of providing for ready removal of the actuator and also 'at plant' electrical isolation — the latter being a mandatory requirement within the CEGB. A padlocking facility is provided to prevent engagement of the plugs to en! oree a disconnected (isolated) condition. A typical actuator box is shown in Fig 5.58. Power supplies for equipment primarily of a portable nature, e.g., welding plant, bolt heating equip-
ment, portable pumps, etc., are provided by wall or ,,teelwork mounted socket outlets. The outlets are triple-pole and neutral, rated 16, 32, 63 or 125 A at 41 . 5 V. All ratings are switched, and feature shortcircuit and earth leakage protection — the latter pri-
FIG. 5.57 Actuator power/control distribution board
— general arrangement
manly for the safety of personnel. The short-circuit protection is provided by fuselinks in the 16, 32 and 63 A units, and the earth leakage feature by residual current circuit-breaker (RCCB). Currently, a mouldedcase circuit-breaker provides the switching, short-circuit and earth leakage functions in the 125 A rating. To prevent the making and breaking of load current on the plugs and sockets, a mechanical interlock is provided on all ratings whereby plant may be connected, i.e., a plug inserted or withdrawn, only when the outlet is switched off. A test facility is provided to enable the user to check the earth leakage protection. Figure 5.59 shows a typical unit.
7 Fuses 7.1 Introduction With the possible exception of specialised control and instrumentation circuitry, for which the reader is referred to Volume F, the fuselinks used in the fusing 409
Chapter 5
470mm APPROX
Switchgear and controlgear
FIG. 5.58 Actuator power/control local disconnection box
arrangements of main, i.e., power and auxiliary circuits, are of the cartridge type. The design of the modern cartridge fuselink, particularly for very high breaking capacities, is too complex a subject for discussion in detail here. However, the following may help towards the understanding of the philosophy of their use in power station applications in the UK.
7.2 Definitions Fuse A device that, by the fusion of one or more of its specially designed and proportioned components, 410
opens the circuit in which it is inserted and breaks the current when this exceeds a given value for a sufficient time. The fuse comprises all the parts that form the complete device. Cartridge fuselink A device comprising a fuse element, or several fuse elements connected in parallel, enclosed in a cartridge usually filled with an arcextinguishing medium and provided with terminals. The fuselink is the part of a fuse which requires replacing after the fuse has operated. Typical LV fuselinks at ratings up to 800 A to BS88:1975 are shown in Fig 5.60.
Fuses
FIG. 5.60 Typical HBC fuse links to BSS: 1975
fuselinks for use in high prospective current circuits are provided with terminals designed for connection into equipment by screw/stud type fastenings.
Current-limiting fuse/ink A fuselink which, during and by its operation in a specified current range, li mits the current to a substantially lower value than the peak value of the prospective current (see cut-off current). Prospective current of a circuit The current that would flow in a circuit if a protective device, e.g., fuse or circuit-breaker, situated therein were replaced by a link of negligible impedance. Prospective breaking current The prospective current measured at a time corresponding to the instant of the initiation of the arc in a fuse during the breaking operation. Rated breaking capacity The maximum prospective breaking current that a fuse is stated to be capable of breaking at a stated recovery voltage under specific conditions.
Fiu. 5.59 415 V, 63 A
socket outlet
Fuse element A part of a fuse designed to melt when he fuse operates.
Fuseiink contact
A conducting part of a fuselink
deigned for the purpose of connecting the fuselink into a circuit. The conducting parts are, essentially, the cartridge body and end caps together with any tttached fittings — lugs, tags, necessary to provide adequate terminal arrangement. As a general rule,
Cut-off current The maximum instantaneous value reached by the current during the breaking operation of a fuselink when the fuselink operates in such manner as to prevent the current from reaching the otherwise attainable value. In other words, cut-off occurs when the fuse operates, i.e., interrupts the circuit before sufficient time has elapsed for the current to reach the prospective value. Cut-off characteristic A curve giving the cut-off current under stated conditions of operation. In the case of AC, the values of cut-off currents are the maximum values reached whatever the degree of asymmetry (of the current). In the case of DC, the values of the cut-off currents are the maximum values reached related to the time-constant as specified. 411
Switchgear and controlgear
Chapter 5
Pre- arcing time
The time between the commencement of a current large enough to cause the fuse element(s) to melt and the instant when an arc is initiated.
1 VALUES GIVEN AP "Ly AT .115V
LI P P 5 65 0 0 vi V VA A LL U ES S A AR RE E U 6 I JE
■
EATER TO 1150: GGRREATER
The interval of time between the instant of the initiation of the arc and the instant of final arc extinction. Arcing dine
Operating time
The sum of the pre-arcing time and
the arcing time. A curve giving I 2 t values (pre-arcing 1 t and/or operating [ 2 0 as a function of prospective current under stated conditions of operation. 2
The I 2 t value divided by the square of the prospective breaking current. The virtual times usually stated for fuselinks are pre-arcing time and operating time. Virtual time
CUTOFF CURRENT PEAK. kA
I 2 t characteristic
10 -
1 0-
Time/current characteristic The curve giving the virtual time (e.g., pre-arcing time or operating time) as a function of the prospective breaking current under stated conditions of operation.
7.3 Required performance Figure 5.61 illustrates 'cut-off', and Figs 5.62 and 5.63 'ti me/current' and c1 2 t let-through' characteristics of cartridge fuselinks to BS88:1975. The current-limiting capability of HBC fuselinks is a particularly attractive feature in high fault level circuits, in that the circuit equipment need be designed to withstand only the thermal and mechanical stresses associated with the value attained by the current at cutoff. In the absence of a current-limiting performance, the whole circuit must be capable of withstanding the very much higher stresses which would otherwise be set up by the passage of the circuit prospective current. Thus, where it is possible and practicable to take advantage of the current-limiting performance of fuses, the circuit equipment may be of appreciably lighter construction, smaller physically and less costly than where the short-circuit protection must, of necessity, be provided by non-current-limiting means, e.g., circuit-breakers. The role of fuses in the applications described in Sections 5 and 6 of this chapter is primarily the provision of short-circuit protection. Where in addition it is necessary to provide protection against more modest values of overcurrent — the protection of motor circuits against overload being a particular instance — the circuit switching device, e.g., the contactor, is designed and equipped to perform that function. As a generality, fuselinks are 'general purpose' or tack-up', or a derivative known as a 'motor circuit 412
0.1
100
0
FIG. 5.61 Cut-off current characteristics
fuselink' which, as the name implies, is intended primarily for motor duty. Essentially, a motor circuit fuselink is a general purpose fuselink with a dual basis of rating; namely, a given current rating with respect to its ability to carry current continuously and a higher current rating with respect to its time/current characteristic. The concept permits exploitation of the ability of a fuselink of compact dimensions to withstand, for a limited duration, circuit overloads such as occur during motor starting — particularly where the drive is switched direct-on-line. By way of example, a fuselink to BS88: Part 1: 1975 rated 63M100 has a continuous current rating of 63 A — and hence a body of dimensions commensurate with that rating — but a time/current characteristic of a 100 A rated fuselink. Thus where, as is usually the case, the rating of the fuselinks required by a given drive is dictated by the magnitude and duration of the starting current, rather than by the steady state running value, a space saving becomes possible. The letter 'M' appearing between the two values of rating serves merely to confirm the motor circuit application. Whilst it is important to note that a dual rated fuselink should not be run continuously at a current exceeding the lower value, e.g., 63 A in the case of a 63M100 rating, it is vital that the circuit in which it
DC switchgear
•h „ , „ ,
ki
; 1I1 IA Vie sasim
DISCRIMINATION 9Er. ,IEEN FL:50 ,_!NKS S ICH 103 THE 'OTAL ; ! OF THE MINOR FUSE LINT DOES NO ExCEED 2
450 400 355 315 250 - 200
1
THE PRE.ARC , NG i 2 : OF THE v0005 EL5E-
4- TOTAL OPERAflNG :
500
-4- TOTAL OPERAT:NG I:. AT 0500 2
4. TOTAL OPERATING 1 1 AT 2!5:., 10 ' - 4- PRE ARCiNG i2t
1 60 125 100
1
1
1
1
80
1 1 1 1 1 1 i i .
0'
i
.TI
10,000 1,000 RMS SYMMETRICAL PROSPECTIVE CURRENT, A
F10.
5.62 Time/current characteristics
is installed be capable of withstanding, at the circuit prospective current, the values of 'cut-off current and 'energy' 0 2 0 let-through commensurate with the higher rating, e.g., 100 A in the example. Cartridge fuselinks of UK manufacture and compliant with the appropriate British/DEF Standard are precision devices which have proved highly reliable in service when applied properly, i.e., selected, in the • of motor circuits, with due regard to: • The ratio of the starting/running current. • The duration of the starting period. • The number of sequential starts to be allowed for, i.e., successive starts without intervals between starts long enough to permit cooling. Hie principles of the selection of fuses in schemes protection is described in Chapter 11.
8 DC switchgear
8.1 General At the beginning of electricity supply, the sources of
200 250 315 355 400 450 SOO 560 630 670
7
0 750
aao !010 '_50
FUSE RATING A
Fla. 5.63 1 2 t characteristics
such supply — dynamo charged batteries of secondary cells — produced unidirectional current (DC). A first essential of any system of supply is means for establishment and interruption of current flow, i.e., switching on and off. The most elementary means are, of course, the coming together, and parting, in ambient atmosphere (air) of contacts of conducting material. The earliest devices for circuit 'making' and 'breaking' were as simple as this. All practicable forms of interruption of an electric current involve the production of an arc, which must be extinguished to complete the interruption. The arc, an intensely hot column of conductive gas, is extinguished by cooling and lengthening to the point where the potential difference (voltage) across the contact gap, as it widens, becomes incapable of sustaining the arc. At full opening of the contacts, the dielectric strength of the gap must withstand the voltage across it. The build-up of dielectric strength across the contact gap takes place similarly in the interruption of AC. However, the process of interruption in an AC circuit is assisted markedly by the occurrence of natural current zeros at every half cycle — arc extinction taking place at or near a current zero. The absence of naturally occurring current zeros in the case of DC thus 413
Switchgear and controlgear
Chapter 5
renders the interruption of such currents a more difficult process. From the simplest of devices initially, switching current in air, the switchgear evolved into open-type, i.e., unenclosed, air-break contact systems, at first operated manually, mounted on vertical panels of insulation material, such as slate. As systems developed, arc control became necessary to achieve satisfactorily reliable interruption. Development along these lines led, in due course, to the circuit-breaker concept as presently understood (see Section 2.1 of this chapter for definition of a circuit-breaker.) Whilst development and general acceptance of the metal-enclosed concept followed rapidly upon the appearance, in the early part of this century, of the oil circuit-breaker in the AC field, DC switchgear continued firmly in the open-type tradition for several decades. However, for many years now, the bulk of DC switchgear in UK power stations has been at least metal-enclosed and, wherever possible, metalclad. A definition of `metalclad' is given in Section 4.2 of this chapter. Broadly, the several types of switchgear equipment comprising a DC system installation, e.g., circuitbreakers, contactor controlgear, fusegear, are two-pole versions of their three-phase AC counterparts.
8.2 System conditions
• System short-circuit level Fault current, kA Time constant, s
Contactors As for AC applications, contactors are selected as follows in accordance with the 'duties' and 'utilisation categories' recognised in BS5424: Part I:
• Motor control Rated duty.
Uninterrupted
Utilisation category:
DC2 where the duty is the starting and switching off, of shunt-motors. DCI where the duty is as for DC2, but with the addition of 'inching' or 'plugging'. DC4 where the duty is the starting and switching off, of series motors. DC5 where the duty is as for DC4 but with the addition of 'inching' or 'plugging'
Mechanical endurance: 1 million no-load operating cycles
Accelerating contactors may be of intermittent duty.
The usual system voltages and fault levels are: • System voltage nominal, V DC
Short-time current capability — the full fault current level of the system for 3 s.
48
110 220 250
20 40 40 40 0.015 0.02 0.02 0.02
• Substantially non-inductive loads switched on for long periods Rated duty:
Uninterrupted
Utilisation category:
DCI
Mechanical endurance: 0.3 million no-load operating cycles
To meet these system conditions, the basic capability
required of the major components of a DC switchgear installation is described in the paragraphs that follow. 8.2.1 Short-circuit withstand strength of busbar systems
• The full fault current level of the system for 3 s, where the busbar protective device is a circuitbreaker. • The full fault current level of the system, as limited in magnitude and duration by the 'cut-off' characteristic of the fuses, where the busbar protective device features fuses. 8.2.2 Current making/breaking and short-circuit capability of main circuit switching devices
Circuit breaker equipment -
Rated short-circuit making and breaking current — 40 kA at a time-constant appropriate to the system. 414
Additionally, contactors must be capable of making and carrying the prospective short-circuit current of the system as limited in magnitude and duration by the associated circuit short-circuit protective devices, i.e., fuselinks. Starting resistors must limit motor starting currents to not more than 250% of the normal full-load current, or such lower value as may be dictated by a particular motor design. They must be capable of carrying starting current for a minimum of five minutes. 9 Construction site electrical supplies equipment 9.1 General The following sections outline equipment for the provision of site electrical supplies at 4 15, 240 and 110 volts AC 50 Hz, single or three-phase, for site construction
purposes.
Construction site electrical supplies equipment
9.2 Portable substations
Fhe equipment comprises: • • •
The substations provide supplies at 415/240 V, derived from an ii kV source. Figure 5.65 depicts a typical arrangement. The transformer in the substation has a rating of
Portable substations. Pori,ible distribulion units 4.15/240 V. Portab!.... distribulion units 110 V.
1000 kVA at a primary voltage of 11 kV. The high
supply scheme is shown in Fig 5.64.
'kV SUPPLIES FROM AREA BOARD OR POWER STATION
ttkV RING MAIN
111A/ RING MAIN
PORTABLE SUBSTATION A
PORTABLE SUBSTATION
No ,5
Cr
Not 11
415/240V PORTABLE DISTRIBUTION UNITS*
No3
*
11 11 11 11 11 110V PORTABLE DISTIRBUT ON UNIT
I
11 11 11 11 11
PORTABLE SUBSTATION D
I
110V PORTABLE DISTRIBUTION UNIT
No.4
WI] PORTABLE SUBSTATION C
FIG.
5.64 Typical site supply scheme
415
Switchgear and controlgear
Chapt er 5
1000kVA TRANSFORMER TRUNKING
415/240V DISTRI6LIT1ON PILLAR
TRLINKING t1kV RING MAIN UNIT
RN LIFTING LUGS
LV CABLES
HV CABLES
SKID BASE
ELEVATION FENCE REMOVED)
ALL ACCESS COORS ARRANGED FOR PADLOCKING
2509mr1 HIGH SECTIONAL METAL MESH SCREEN
2300mm MAX
PLATE STEEL FLOORING
4600mm APPROX
PLAN
DISTRIBUTION PILLAR 4151240V 3 PHASE & N
1000 kVA TRANSFORMER
IIkV RING MAIN UNIT UV RING MAIN
11 11 11 11 11 11 400A
630A
DIAGRAM OF CONNECTIONS
Fro. 5.65 Portable substation, 11 006/415/240 V 416
Construction site electrical supplies equipment we switchgear comprises an oil-immersed, on-load main unit with tee-off fuse switch incorporate high breaking capacity (HBC) fuses. Operating rae-chanisnis are of the independent manual type. The s,.vitch is tripped automatically upon operation anv one fuse. Nlechanical interlocking is provided protect the operator from contact with live parts o
replacing. fuselinks. Integral earthing devices are to facilitate the earthing of the transformer and one or both ring, main cables. A safety device pres aLicess to switches or bushings unless all switches it in the 'earth' position. A maximum demand am-
current operated, is fitted to the tee-off fuseh portion. Cable boxes with cable glands pointing • i tc ertically downwards are provided for the incoming aild outgoing ring main cables. The 415/240 V distribution pillar is a weatherproof ,hect steel housing having padlockable access doors front and rear. The base plate is constructed in two
.eetions which can be removed separately to aid the process of cable installation. The base plate is sealed a2ainst the ingress of moisture or vermin. The fuse units are screened so that work can be carried out on He load side of any circuit when the adjacent circuits
are 'live'. The pillar unit comprises:
• Three 630 A (three-phase and neutral) fuse units 0,ith 630 A HBC fuses, neutral links and gland entries for 4-core power cables. • Three 400 A (three-phase and neutral) fuse units ith 400 A HBC fuses, neutral links and gland entries for 4-core power cables. Lich circuit is fitted with a current-transformerperated maximum demand ammeter. (he pillar is fitted with a phase selector switch and .1 oltmeter, visible from the front of the unit when the Joors are closed. Door operated bulkhead lighting is .i kluded, together with an electric heater of adequate to prevent condensation. These items are uoplied directly from the busbars and protected by I I li C fuses. I he connecting busbars between transformer, HV • ichgear and pillar are of copper, enclosed in a trunking. 1 copper earth bar with a section of about 500 min inm is provided, to which is connected the neutral c.irthing li nk of the distribution pillar, the earthing points of equipment and all metal framework and reens. The earth bar is connected to the site earthing
padlockable access gates, is affixed around the perimeter of the assembly. A label is attached to the fence indicating the gross weight of the equipment.
9.3 Portable distribution units (415/240 V) These distribution units provide supplies at 415/240 V. The equipment is enclosed in a weatherproof housing mounted on a rigid steel base, suitable for handling by crane or winch onto a roughly levelled hard-core foundation. Figure 5.66 depicts a typical construction.
The units are equipped with triple-pole and neutral fuse switches complete with NBC fuselinks, entries for power cables, one 12-way 32 A triple-pole and neutral distribution fuseboard feeding 32 A socket outlets, featuring earth leakage protection. The unit is provided with a voltmeter, visible when the doors are closed. Bulkhead type light fittings are provided at front and rear. Electric heaters are fitted to combat condensation. These items are supplied direct from the busbars and are protected by HBC fuses. The unit enclosure is provided with a substantial earth terminal for connection to the site earthing system.
9.4 Portable distribution units {110 V} These distribution units provide supplies at 110 V single or three phase. Units are rated 5, 10 or 25 kVA. Figures 5.67 and 5.68 illustrate typical constructions. The units are of sheet steel weatherproof construction mounted on rubber-tyred wheels. All components, such as fuse-switches and distribution boards mounted on the transformer tank, are secured by welded attachments. The units are equipped as follows:
Rating kVA 5
,
,
[he equipment is mounted on a rigid steel baseframe , i][!,thle for handling by crane or winch onto a roughly 1:: ■ c.11ed hard-core foundation. Steel plate flooring is
nosuioned around the plant, fixed to the frame, to Pro‘Ide safe access for operation and maintenance. -1 metallic fence, approximately 2500 mm high, secried to facilitate easy removal and provided with
10
25
Input 415 V
Output 110 V
63A triple-pole switch
6-way, 20 A three-phase and neutral distribution fuseboard
63A triple-pole switch
I2-way, 20 A three-phase and neutral distribution fuseboard
63A triple- pole switch
Three-phase and neutral fuse-switch fitted with 1 60 A fuselinks
No of Socket outlets
6
12
The transformer is a three-phase ON type having a voltage ratio of 415/115 V at no-load, suitable for operation on a nominal 415 V three-phase system having its neutral point solidly earthed. An earthing terminal of approximately 12 mm dia. x 25 mm long is provided on the enclosure. Neutral links are of the bolted type. Distribution fuseboards are connected directly to the LV terminals of the transformers. 417
Switchgear and controlgear
Chapter 5
BUSBAR CHAMBER
VOLTMETER
BUSBAR CHAMBER
LIFTING LUGS
-■■■•■■,.
— -r 2COA TP&N
ELI
0
[
aCOA TP&N IN
200A TP&N
0
_
1C0A TP&N 12 WAY 32A TP&N TP&N
TP&N DISTRIBUTION FUSEBOARD EARTHING POINT II
I/ / e
/
/I
II
/0.
I
I
e
1800mm APPROX
FRONT ELEVATION (DOORS OPEN)
SIDE ELEVATION
INCOMING SUPPLY
?I,
400A
TI I EE P (A N g N E UT l 'ISAIE_ (TP&NI
J5 FUSE SWITCHES
THREE PHASE AND NEUTRAL FUSE BOARD
32A SOCKET OUTLETS
REAR ELEVATION (DOORS OPEN)
Fro, 5,66 Portable distribution unit, 415/240 V 4'18
Zc
b
Construction site electrical supplies equipment
Ymm
X rt11111
LIFTING LUGS
,
JEuTRAL EARTH LINK
Li
11 , 63A TP SWITCH
SOCKET O u TLETS EARTH TERMINAL
DISTRIBUTION FUSE BOARD
INCOMING 4I5V 3 PHASE. 50Hz
RATING kVA
01ST RIB— UTION BOARD
No. OF SOCKETS
6 WAY
12 WAY
X
Y
7
6
760
760
640
12
920
920
840
63A TP SWITCH
5 10
APPROX DIMENSIONS
_
415,110V TRANSFORMER
NEUTRAL EARTHING
THREE PHASE AND NEUTRAL DISTRIBUTION FUSE BOARD
•■■••
t*".
■
rm
16A SOCKET (Th e•—•■ (Th f.m (Th (Th (-1 OUTLETS
•
DIAGRAM OF CONNECTIONS
Fia. 5.67 Portable distribution units, 110 V/5 and 10 kVA
419
Switchgear and controlgear
Chapter 5
12C.-.; mr, APR FI C X
1000mm APPROX
71,
MOnini APPROX
LIFTING LuGS
TP AND N FUSE S,V,TCH
INCOMING 415V 3 PHASE, 50Hz
63A TR SWITCH
25kVA 415/110V TRANSFORMER
TP AND N FUSE SWITCH FITTED WITH 160A FUSE LINKS
NEL;THAL EAPTHING LINK
DIAGRAM OF CONNECTIONS
FiG. 5.68 Portable distribution unit, 110 V/25 kVA
420
Future trends in development and application Socket outlets are situated on the exterior of the sheet housing, and connected to the distribution board qeel by cable. of fuse-switches and distriThe earthing terminals
i on boards are connected to the earth terminal on The neutral point of the LV he transformer tank. inding is connected to the earth terminal on the
mit
;Linsformer tank through a bolted link located in an Jccessible position.
10 Future trends in development and application 10.1 General With the trend towards use of plant requiring minimum maintenance, and the ever present quest for first cost and space optimisation, the types of switchgear on offer to the applications engineer has changed dramatically recent years. That such changes have particularly affected the voltage range from 1 kV to 36 kV can be attributed to the fact that investment worldwide in clectrical plant is necessarily biased toward distribution vsterns. Whereas the ratings required of distribution switchgear are generally lower than those of power station switchgear, there is no doubt that research and development aimed at the former has also been of benefit to the latter. Since switchgear exists to control and protect the electrical system to which it is connected, it is of paramount importance that it can perform these duties with maximum reliability. The duty of short-circuit protection has particular significance in power stations, since the close coupling of several high energy sources leads to very high short-circuit currents and the mechanical stresses resulting therefrom to system plant, husbars and cabling. It is a well established fact that the failure rate of any item of engineering plant is proportional to the number of components comprising that item. A comparison between the latest designs of interrupter unit for switchgear and long established designs shows clear]y that there is a distinct trend towards the reduction of components, particularly in the interrupter. This move has doubtless been assisted by an increasing understanding of arc control technology and the utilisation of modular construction, together with new materials a,nd assembly methods. Statistics show that the majority of switchgear failures can be attributed to mechanical rather than electrical breakdown. Switchgear development has therefore eoncentrated much effort upon improving mechanical reliability. A distinct merit of the latest interrupter devices is that the mechanical stresses occurring within the switchgear during short-circuit breaking and making have been reduced and the resultant energy requirements of the opening and closing mechanisms have
decreased proportionally. These changes not only improve the mean time between failure but also achieve a marked reduction in operating storage batteries. The trends toward simpler and more reliable construction also enable costs to be reduced, both for initial purchase and for subsequent preventive and corrective maintenance. However, the engineer must always be conscious of the fact that innovation and improvement do not always go hand in hand. New designs of switchgear still require careful evaluation and thorough type testing. Where switchgear forms part of 'strategic' or 'safety related' systems, in which its failure could have serious effect, then proven service reliability may need to be demonstrated prior to its full scale adoption. Trial installations for evaluation purposes are of long term benefit both to user and manufacturer.
10.2 Oil-break switchgear Switchgear employing oil for both insulation and inter rupting purposes has not found favour for application in UK power stations for many years, not least because of the hazards of explosion and fire which, although minimised by careful design, can never be eliminated. Nevertheless, the oil circuit-breaker, whether it be of the bulk oil or minimum oil type, still continues to give reliable service in distribution systems but is steadily being replaced by the new ranges of low maintenance, low fire-risk switchgear now available.
10.3 Air-break switchgear The progressive development of the early air-break 'knife switch' with plain gap into a reliable circuitbreaker has taken a number of decades and has today been perfected to the level where sophisticated interrupting devices, employing magnetic blow-out circuits, arc guidance systems and arc-resistant insulation, enable very high breaking capacities to be achieved with air-break switchgear. The use of such complex and bulky interrupting devices, coupled with the more generous air clearances required, is not without its penalties. These ate, for power station auxiliary HV switchgear, evidenced by the i mpressive size and weight of switchgear panels, their high-initial cost and the skills required to perform major maintenance work. There have been some savings possible at HV with the introduction of the motor switching device, which has been described earlier in this chapter, and further development of this device is expected albeit by employing power fuses in combination with low rated vacuum or alternative modern arc control devices. At LV, the application of reliable high breaking capacity fuses of UK design means that the demand for high capacity air-break circuit-breakers is generally li mited to main feeder circuits only. However, some other industrialised countries were less successful in 421
Switchgear and controlgear the development of HBC fuses and as a result a viable alternative known as the moulded case circuit-breaker ( MCCB) was developed and subsequently introduced to the UK. The moulded case circuit-breaker, as its name implies, uses moulded insulation materials, permitting space and weight reduction. in some instances the filler in the moulding material is claimed to assist in the arc extinguishing process by producing gases favourable to current interruption. Current-limiting properties, similar to those of HBC fuses, can also be utilised to reduce fault damage and a regime of rating steps (as for fuses) must also be followed to ensure discrimination. As an alternative to 'traditional' fuse switchgear, the MCCB can also fulfil a role within motor starter circuits. MCCBs now available on the UK market have found limited favour with some users but have yet to make their mark in UK power station applications. With a specified service life for power station plant MCCBs in 'non-maintainable' form would not be acceptable. The maintenance of power station switchgear at service capability is based upon the programmed overhaul/repair of equipment installed for the station designed life. Whilst 'maintainable' moulded-case circuitbreakers may have a place, the 'non-maintainable' form is as yet unacceptable by virtue of the difficulty of determining the performance capability after a period of service, particularly if fault clearances have been a feature of that service.
10.4 Air blast switchgear -
Exploitation of the improved 'dielectric withstand of air subjected to pressures above atmospheric level has resulted in present day designs of air-blast switchgear. Designs of air-blast interrupter employing compressed air stored at pressures of the order of 30 bar, with sophisticated gas flow technology applied to the nozzles and contacts in the arc region, are capable of achieving the highest short-circuit breaking capacities demanded today. These units therefore find ready application as generator circuit-breakers for the largest steam turbinegenerator units available and can be forced cooled, where necessary, to match generator load currents. The high cost of air-blast switchgear which must also include ancillary compressor and air storage plant, plus the noise accompanying each switch opening, precludes the wider application of these units to power station general auxiliary systems. Similar air-blast switchgear was also developed for distribution and transmission systems up to highest EHV levels. However, with the advent of new arcinterruption technology and more environmentally acceptable low maintenance switchgear, the air-blast circuit-breaker has declined rapidly in favour during the last decade and now worldwide is being applied only under special circumstances. This trend can be expected to influence future application of air-blast 422
Chapter 5 technology to power station generator switchgear where alternatives are now available for all but the very highest short-circuit breaking capacities.
10.5 Vacuum switchgear Although researched in the 1920s, vacuum arc-interrupting devices did not achieve commercial viability until the 1960s. The factory sealed vacuum interrupter has subsequently introduced to the switchgear field a unit which is claimed by some to approach the 'ideal' circuit-breaker of electrical theory. However, the aura which tends to surround all 'black-box' components has also given rise to some concern over their performance and reliability, particularly in power station applications, in their behaviour when switching motors and the possibility of loss of vacuum. Satisfactory service experience with vacuum switchgear during the last decade has dispelled most of the doubts. Furthermore, research in the laboratory and in the field has tended to confirm that some phenomena are not unique to vacuum interrupters and that for critical service conditions some special precautions may be appropriate to both established and innovative designs. The success of any electric arc-interrupting device lies in its contact geometry and, particularly with the vacuum unit, the chemistry of the contact materials is also of great significance. Whilst the reader wishing to study the contact materials technology in detail can refer to the many learned papers now published on the subject, it is sufficient to note here that it is the precise composition of the basic contact metal, copper, together with controlled additives and the exclusion of impurities, which dictate performance. Vacuum interrupter development has produced units for circuit-breaker application, with its demands for high short-circuit breaking capacity and moderate number of switching operations, and for contactor application, with moderate short-circuit breaking capacity and high number of switching operations. A basic advantage of the contactor interrupter, as manufactured in the UK, is that it provides a 'soft' operating characteristic particularly suited to regular switching of load currents including high reactance transformers and small motors, etc. Compared with the contactor type, the circuit-breaker interrupter has a relatively 'hard' characteristic. This is presently unavoidable, being an inherent feature of interrupters designed specifically for very high currents, i.e., short-circuit currents. Briefly, a 'soft' interrupter is one with a negligible propensity to 'current chop', and thereby produce overvoltage likely to damage plant insulation. Conversely, a 'hard' interrupter is one with a tendency towards such behaviour. Current chopping is the term used to describe the sudden reduction to zero, during the process of interruption, of an alternating current at a time other than the instant of a natural zero. Theoretically, an interrupter 'breaks' an alternating current
Future trends in development and application Mien the dielectric strength across the arc gap at a natural zero becomes sufficient to prevent the recovery re -establishing the current flow. j :a oe (across the gap) llows, therefore, that a dielectric strength suffifo- bring about interruption of a high value of o , a short-circuit current, will be more severe , ivrent ' necessary to deal with much lower values. Thus „th ics of current relatively low, by comparison the maximum capability of the interrupter, which
i(11,usceptib'e to chopping, i.e., forced to zero before ,, r e natural zero. be instant of a Vacuum contactor interrupters in combination with form motor switching devices, are avail1113C fuses to rated voltage from 1 kV to 7.2 kV. Such units jblc successfully applied in limited quantity in 1 1 , 1 %e been LK power stations and it is anticipated that their oe will increase, particularly where they can demonJ first cost advantage over air-break types. Figgrate a ures 5.69 and 5.70 illustrate examples of controlgear i.c..ituring vacuum interrupters in association with HBC fuse protection. Vacuum circuit-breakers have also been successfully pplied in UK power stations but await full recognia tion as an alternative to the current standard air-break units. The trend to wider application of vacuum circuitbreakers can be expected to follow demonstration of the highest short-circuit breaking and normal current capacities appropriate for the largest power plant systems, i.e., 40 kA and 3150 A respectively. Rated voltages of 3.6 kV and 12 kV will be required and although a motor switching duty at 11 kV is specified, this will relate to large motors i.e., 1000 kW and above.
10.6
S F6 switchgear
Research into
the use of SF6 (sulphur-hexafluoride)
for electrical
insulation purposes can be traced hack to the 1930s but it was not until the 1950s that its performance as an insulation medium was noted. ‘,1: 6 is odourless, colourless, non-toxic and non-flaminable. At normal temperature and pressure its specific density is five ti mes that of air and its thermal transfer coefficient 1,6 times that of air. Its dielectric strength at only 3 atmospheres absolute is comparable to that of electrical insulating oil. Initial application of SF 6 to switchgear was at transinksion voltage levels where it was a logical development of the air-blast principle to employ a gas other 12L1S
than air. The need to seal the gas system in order to exclude air and moisture, together with problem experienced with compression and storage of recycled gas, led to the derivation of the 'puffer' interrupter, in which a minimal overpressure is held for insulation purposes and where, during the interrupting cycle, a local blast of gas is created in the region of the arcing contacts by a direct-driven piston/cylinder unit. At transmission voltage levels, development continues into interrupters of increasing breaking capacity, the trend towards a simplification of units for use at voltages from 1 kV to 36 kV has also progressed. The puffer principle is presently retained at these voltages for short - circuits of 15 20 kV and above. Designs are also available at low fault levels and are continuing in development by a number of manufacturers worldwide to higher fault levels, using various forms of self-extinction system, including electromagnetic deflection and rotating arc techniques. The selfextinguishing interrupter results in designs of switchgear with minimal requirements in operating energy, whilst the insulating and heat conductive capabilities of SF 6 enable unit sizes to be held to a minimum. The specialised metalclad and phase-segregated generator circuit-breaker is now available with SF 6 technology for all but the very highest normal current and fault ratings. Short-circuit breaking capacity up to 100 kA has already been achieved using selfextinguishing principles and it can be expected that development will continues, resulting ultimately in the phasing out of air-blast switchgear for generator switching duties. The exploitation of the electrical insulation properties of SF6 in isolation from its arc interrupting characteristics occurred in the late 1960s in the UK, when trial installations of multiple-unit vacuum interrupters immersed in SF6 gas were made on the 132 kV system. Gas insulation, also employed at EHV levels for current and voltage transformers, enables internal dimensions to be minimised. Also, because a small overpressure is employed, the enclosure gives full environmental protection. More recently, some European manufacturers have introduced HV metalclad switchgear with SF6 gas insulation and oil or vacuum interrupters. Whilst such equipment becomes particularly attractive because of space saving at voltages in the range of 24 kV to 72 kV, it is less important at power station auxiliaries system voltages, especially if available only with fixed type isolation. -
423
JeeEloiluop pue Flo 5.69 Switchboard formation of control gear featuring vacuum interrupters in association with IIBC fuse protcciion Jr 3.1 kV service I nclusirial Controls Lod) (see also Colollr photograph betwceil pp 496 .1 mi 497)
Future trends in development and application
Fit„ 5.70 Example of control gear featuring vacuum interrupters in association with HBC fuse protection — for 3.3 kV service, showing the demonstration of the circuit earthing switch (GEC Industrial Controls Ltd) (see also colour photograph between pp 496 and 497) 425
Switchgear and controlgear
11 Bibliography
Chapter 5 8S3938: Specification for current transformers: 1973 (19831 BS3941: Specification for voltage transformers: 1975 119821
11.1
British Standards {BS)
Where an International Electrotechnical Commission (lECI number is given, the British Standard is identical with the IEC document, BS4727: Part 1: Glossary of electrotechnical, power, telecommunication, electronics, lighting and colour terms: Part 2: Terms particular to power engineering Group 06. Switchgear and controlgear terminology (including fuse terminology): 1985 BS5311: Parts 1-7: Specification for a.c. circuit-breakers of rated voltage above 1 kV: 1976 8S5227: Specification for a.c. metal-enclosed switchgear and controlgear of rated voltages above 1 kV and up to including 72.5 kV: 1984 BS4752: Part 1: Specification for switchgear and controlgear for voltages up to and including 1000 V a.c. and 1200 V d.c. Part 1. Circuit-breakers: 1977 (IEC 157-1975: IEC 157-1A: 19761 88775: Part 2: Specification for contactors: Part 2, a.c. contactors for voltages above 1 kV and up to including 12 kV: 1974 BS3659: Specification for air-break circuit-breakers for alternating current systems above 1 kV and up to and including 11 kV: 1963 ( withdrawn and replaced by BS5311) BS5424: Part 1: Specification for controlgear for voltages up to and including 1000 V a.c. and 1200 V d.c. Part 1, Contactors: 1977 1IEC158-1: 1970, IEC158-1A: 1975) BS5419: Specification for air-break switches, air-break disconnectors, air-break switch disconnectors and fuse-combination units for voltages up to and including 1000 V a.c. and 1200 V d.c.: 1977 1IEC408: 19721 BS5486: Part 1: Low-voltage switchgear and controlgear assemblies. Part 1, Specification for type-tested and partially type-tested assemblies (general requirements): 1986 1IEC439-1: 1985) BS5490: Specification for classification of degrees of protection provided by enclosures: 1977 (IEC529: 1976) 9S1432: Specification for copper for electrical purposes. Strip with drawn or rolled edges: 1970 B52898: Specification for wrought aluminium and aluminium alloys for electrical purposes. Bars, extruded round tube and sections: 1970 8S5253: Specification for a.c. disconnectors (isolators) and earthing switches of rated voltage above 1 kV: 1975 1352692: Part 1: Fuses for voltages exceeding 1000 V a.c. Part 1. Specification for current-limiting fuses: 1986 (IEC2821: 1985)
426
BS162: Specification for electric power switchgear and associated apparatus: 1961 BS6581: Specification for common requirements for high-voltag switchgear and controlgear standards: 1985 IIEC694: 1980)
e
854941: Part 1: Specification for motor starters for voltages up to and including 1000 V a.c. and 1200 V d.c.: 1979 1IEC292-1: 1969, IEC292- 1A: 19711 BS142: Electrical protection relays: 1982 BS158: Specification for the marking and arrangement of switchgear busbars, main connections and small wiring: 1961 (withdrawn) BS3535: Specification for safety isolating transformers for industrial and domestic purposes: 1962 BS88: Parts 1 and 2: Specification for cartridge fuses for voltages up to and including 1000 V a.c. and 1500 V d.c: 1975 11982) 854343: Specification for industrial plugs, socket-outlets and couplers for a.c. and d.c. supplies: 1968 85196: Specification for protected-type non-reversible plugs, socket outlets, cable couplers and appliance-couplers with earthing contacts for single phase a.c. circuits up to 250 volts: 1961
11.2 Electricity supply industry (ESI) Standards ESI Standard 37-1: 415 V a.c. switchgear, controlgear and fusegear ESI Standard 37-3: A.C. metal-enclosed switchgear and controlgear of rated voltages 3.6 kV and 12 kV: Part 1: Circuit-breaker equipment (air-break): Part 2: Fused switching device equipment of 3.6 kV rated voltage ESI Standard 50-18: Design and application of ancillary electrical equipment
11.3 Other relevant documents Memorandum on the Electricity Regulations (SHW 928): UK Factories Act: 1961 DEF 59-100 Part 1: Fuseholders, carriers and bases electrical fuse (Block and extractor post types) DEF 59-96 Part 1: Fuselinks electrical Power Circuit Breaker Theory and Design: Edited by C.H. Flurscheim: Published by Peter Peregrinus Ltd
CHAPTER 6
Cabling Introduction
2
Cable systems and layout 2.1 Segregation requirements 2.1.1 Segregation requirements for fossil-fired and hydro power stations 2.1.2 Segregation requirements for nuclear power stations 2.1.3 General layout requirements
3 Cable types 3.1 11 kV cables 3.2 3.3 kV cables 3.3 415 V cables 3.4 Cables for DC power circuits 3.5 Multicore control cables 3.6 Multipair control cables 3.7 Short-time fireproof cables 3.8 Linear heat detecting cables 3.9 Developments in cable design 3.10 Thermal ageing 3.11 Mechanical performance 3.12 Electrical tests 4 Power cable system design 4.1 Introduction 4.2 Current rating for continuous operation 4.2,1 Maximum conductor temperature 4.2 ,2 Ambient temperature 4.2.3 Conductor temperature rise 4.2.4 Permissible current ratings 4.2.5 Rating factors 4 2.6 Single-core cables in parallel 4.3 Fault current and duration 4.3.1 Short-circuit faults 4.3.2 Earth faults 4.3.3 Overload current 4.4 Motor starting 4.4.1 Motor starting current 4.4.2 Motor starting times 4.5 Cable voltage regulation 4.6 Cable system design 4.6.1 Feeder circuits 4.6.2 Motor circuits 4.7 Practical examples 4.7.1 Feeder circuits 4.7.2 Motor circuits 5 Control and instrumentation cable systems 5.1 Signal levels 5.2 Cable types 5.3 Cable interference 5.3.1 Interference in multipair cables 5.3 .2 Interference in multicore cables 53.3 Circuit considerations 5.4 Control and instrumentation cable system design 5.5 Cable network system using jumpering 5.5.1 Basic principles of cable network 5.5.2 Switchgear and interlocking equipment 5.5.3 Design of cable network systems 5.5.4 Application of cable network systems 5.5.5 Testing and commissioning of a control network system
5.5.6 Plant-mounted devices 5.5.7 Application of short-time fireproof cables 6 Cable support systems 6.1 Introduction 6,2 Design philosophy 6.3 Basic system components 6.4 System design and application 6.5 Seismically qualified cable supports 7 Cable installation practices 7.1 Introduction 7.2 The need for cable restraint 7.3 Cable cleating design parameters 7.4 Cleating philosophy for cables installed on steelwork 7.4.1 Straight horizontal runs on ladder racks 7.4.2 Straight vertical runs on cantilever arms 7.4.3 Horizontal runs in a vertical plane 7.5 Installation practices for cables installed other than on support steelwork 7.5.1 Direct in ground 7.5.2 Installed in ducts 7.5.3 Routing in concrete troughs 7.6 Cable pulling 8 Cable performance under fire conditions 8.1 Tests on a single cable or wire 8.2 Cable installations having reduced fire propagation 8.3 Oxygen index tests 8.4 Smoke tests 8.4.1 Test methods 8.4.2 Use of test information 8.5 Corrosive gas emissions 8.6 Toxic gas emissions 9 Cable accessories 9.1 Cable glands 9.1.1 Background to gland design 9.1.2 Gland construction 9.1,3 Gland sizing 9.1.4 Installation 9.2 Power cable conductor terminations 9.2.1 Fittings for aluminium conductors 9.2.2 Fittings for copper conductors 9.2.3 Formed terminations 9.2.4 Bolting terminations to equipment 9,3 Conductor terminations for control cables 9.3.1 Crimped conductor terminations 9.3.2 Wire wrapped terminations 9.4 11 kV terminations 1 0 Fire barriers 10.1 Introduction 10.2 Performance requirements 10.2.1 Magnitude and type of fire 10.2.2 Proximity of the fire to the barrier 10.3 Fire test requirements 10.4 Additional performance criteria 10.5 Fire doors 10.6 Penetrations 427
Cabling 11
Chapter 6
Earthing systems 11_1 Introduction 11.2 Differences in earth potential 11.2,1 Definit i ons 11.2.2 Acceptance criteria 11,3 Earthing systems design 11.3.1 Systems having remote neutrals 11.3.2 Faults on internal systems 11_3 3 Lightning protection 11.3.4 Additional considerations 11.4 Earth electrodes 11.4.1 Sheet steel piles 11.4.2 Cylindrical steel piles 11_4.3 Earth rods 11.4.4 Earth strip 11.5 Earth network construction and plant bonding 11.5.1 Main earth network 11.5.2 Instrument earth network 11.5.3 Earth bond cable sizes 11.5.4 Plant bonding arrangements 11.6 Testing 11.6.1 Earth resistivity measurement 11.6.2 Earth electrode resistance measurement 11.6.3 Commissioning tests 11.6.4 Routine tests
12
General requirements Lightning magnitudes and risks Application of requirements to power stations Protection system design Main and gas turbine chimneys Main buildings Other buildings Buildings requiring special considerations Fuel oil storage tanks Flammable gas production and storage plant Assessment of risks of sideflashing and interference Inspection, testing and records
Design and management techniques 14.1 Introduction 14.2 Planning 14.3 Design 14.3.1 Layout 14.3.2 Cable support systems 14.3.3 Information from plant contractors 14.3.4 Cable systems and electrical circuit design 14.4 Installation and contract management information 14.4.1 Introduction 14.4.2 The aims and functions of TPI cabling 14.4.3 Designing
15
References
Appendices A
Values of resistance and reactance for single-core elastomericinsulated cables I90 ° C maximum conductor temperature)
B
Values of resistance and reactance for multicore PVC-insulated cables (70 ° C maximum conductor temperature)
C
Current ratings for elastomeric-insulated cables
D
Current ratings for PVC-insulated cables
E
Rating factors for variations in thermal parameters
Lighting, heating and small power systems
F
Cross-sectional area of armour wire
13.1 Introduction 13.2 Lighting system design 13.2.1 Objectives 13.2.2 Specification 13.2.3 General planning 13.2.4 Detailed planning
G
415 V motor parameters and selected fuse sizes
H
Maximum cable route lengths
1 Introduction The cabling system within a power station performs the essential function of connecting mechanical, electrical and control equipment together to form a total working entity. Cabling systems therefore form an interface between a variety of plant supplied under a large number of electrical and mechanical contracts, and information has to be drawn from each of these to complete the cable system design. During the power station construction period cabling systems are dependent on plant having been installed so that connections can be completed. It can therefore be seen that cabling is an important item in the organising and planning of design functions and site activities. Furthermore, the number of cables has steadily increased with the size of boiler/turbine units, mainly due to the growth of control and instrumentation func428
14
Lightning protection 12.1 12.2 12.3 12,4 12.4.1 12,4,2 12.4.3 12.4.4 12,4.5 12.4.6 12.5 12.6
13
13.2.5 Appraisal 13.3 Emergency lighting systems 13.4 Lighting of special areas 13.4.1 Battery rooms and chlorination plant rooms 13.4.2 Hydrogen plant (Division 1 and Division 2 areas) 13.4.3 Central control rooms 13.4.4 Hazard warning lights 13.5 Supplementary heating and minor power systems 13.6 Distribution system 13.6.1 General 13,6.2 Isolation and switching of individual fittings 13.6.3 AC supplies 13.6.4 DC supplies 13.6,5 Cabling
I
Main protection for feeder and motor circuits
J
Advantages and disadvantages of various lamps used for lighting power station interiors
tions. The number of cables installed on a power station varies with the type of plant, i.e., hydro, coal, oil or nuclear. Considering 660 MW units, the quantities of cables involved at the time of writing for recent projects are Cables per unit
Cables for station services
Total
Littlebrook D (3 units, oil-fired)
6630
6890
26 780
Drax Completion (3 units, coal-fired)
7170
8850
30 360
16 870
17 570
51 310
Heysham 2 (2 units, nuclear AGR)
The average cable route lengths for these projects varies from 51 m on Littlebrook D to 59 in on Heysham 2 and 74 m on Drax Completion. This means that
Cable systems and layout some 3030 km of cable will be installed on the Heyproject. Considering Heysham 2 further, it is sham 2 worthy of note that approximately 70% of the cables re associated with control and instrumentation. a The types of cables used in power stations range from control and instrumentation multipair armoured having_ 0.5 mm- conductors, up to 11 kV power a bi es cables having a maximum conductor size of 500 mm 2 . In addition there are requirements for special cables h as linear heat detectors to sense fires and shortsuc cables which are designed to keep their ti me integrity for a specified period under fire conditions. The cable system also includes accessories such as cable supporting steelwork, cable glands and conductor terminations. Power stations tend to have requirements which differ from normal industrial standards because of their size, complexity and the security needs of such high investment plant. Therefore very often nati onal and international standards are not appropriate and in house' standards have to be prepared. To ensure that only approved equipment of the required standard is installed in a power station, the CEGB operates a type approval system. This chapter is designed to give a comprehensive insight into cable system requirements including hardware, layout, design and installation. It also covers items closely related to cabling such as earthing, lighting, heating and small power systems.
The criteria applied to conventional stations is that the output of not more than one unit should be lost in a single cable fire. To segregate the equipment of one unit from another alone is not adequate, since units are normally dependent on common station services which must also be secure. It should also be realised that although a fire may be contained to involve only the equipment of one unit, the smoke and fumes of the fire may cause further loss of generation due to the evacuation of operations staff and as a result of damage to light current equipment from corrosive fumes. In achieving the segregation necessary to prevent the loss of more than one unit it is also often possible to achieve a degree of segregation within a unit without additional cost. This can be usefully applied to duplicated auxiliaries where the loss of one may cause a reduction in output, but not necessarily a unit loss, and can improve the security of duplicated services and hence reduce the risk of plant damage and prolonged outage. A basic summary of the requirements for segregation is given in Table 6.1. It is important to note the differences between basic requirements and optional i mprovements to the security of the system that can be made at no additional cost. In conventional stations, all barriers provided for segregation requirements should have a minimum of one hour fire rating. Where cables are installed direct in the ground, a separation distance between segregation groups of one metre is considered adequate.
2 Cable systems and layout TABLE 6.1
2.1
Segregation requirements
Before discussing layout in general, it is necessary to understand the segregation and separation requirements for various station types. The station layout, from the very beginning, has to take into account the disposition of ancillary plant and interconnecting cables to ensure that segregation requirements can be achieved. Segregation is provided to limit damage under accident conditions such as fire. Segregation is defined as the physical division or isolation of one group of cables or plant from another by an enclosure or barrier of a certain specified fire rating. The barrier may be brick, concrete or special fireproof partitioning as described in Section 10 of this chapter, Separation is defined as the division of groups of cables by distance alone. Segregation in fossil-fired and hydro plant is primarily provided to limit economic loss. However, in nuclear power stations it is provided for nuclear safety as well as economic reasons. 2.1.1 Segregation requirements for fossil-fired and hydro power stations Segregation in fossil-fired and hydro power stations is provided to limit economic loss in the event of fire.
Basic segregation requirements for conventional plant Plant
Segregation requirement
Unit — Unit
Mandatory
Station A — Station B
Mandatory
Unit — Station
None
Main plant — Standby plant
Yes if no cost penalty
Main plant — Emergency DC or guaranteed AC
Mandatory
Alternative DC tripping supplies
Mandatory
It is a basic requirement that cabling of one unit be segregated from the cabling of all other units. This must be achieved on all major cable routes by the provision of suitable fireproof enclosures and barriers to prevent spread of fire from one unit's cabling to another, and also to contain combustion products. In the case of turbine halls and common boiler houses, clearly it is not practical to enclose all minor cable routes to achieve segregation and, because of the limited amount of cables, there is no need to contain the combustion products. Therefore in the case of these minor cable routes, segregation is achieved by isolating one from the other by distance. 429
Cabling Segregation requirements for station cables and plant will depend on the system design. When one station transformer is provided for each unit, electrical station services are provided on a unit basis. In this case, cables for these services will be segregated by fire barriers from the station services cables associated with other units. If, however, two station transformers are used to provide station services for the whole station, then a different solution is required. In this case, duplicated plant necessary for the operation of the station may be designated 'Station A' and 'Station B', and full segregation by fire barrier applied between the two designations. There is no need to segregate station cables from unit cables providing that in any one incident the total loss is not greater than one unit and/or half the station services. Main CW pumps are normally fed from a station system since these are installed hydraulically on a shared station basis. For CW pumps, cabling should be provided on a sufficient number of segregated routes such that no more than the output of one unit will be lost in a single incident.
Where gas turbines are installed, these are normally on a unit basis and segregation should be provided such that the output of only one gas turbine is lost in a single incident. Another area where it is considered essential to provide segregation is where an emergency DC or guaranteed AC drive is provided for plant safety, as for example, the turbine lubricating oil supply. In these cases, full segregation by fire barrier should be provided between the main drive and the emergency drive. Where duplicate DC supplies for switchgear tripping are provided, these should be segregated from each other over their entire lengths. This requirement stems from instances where, under fire conditions, switchgear tripping supplies have been lost before main circuits have been tripped. Where segregation is not possible, it is permissible for one of the DC supplies to be cabled in short-time fireproof cable of the type described in Section 3.7 of this chapter. We can now consider areas where segregation is not mandatory but which will result in better availability and security and will be employed if it can be incorporated without additional cost. The first area to consider is the II kV supplies to the unit which are derived from the unit transformer, station transformer or via interconnectors (see Chapter 1 System design). Often segregation can be readily achieved between the interconnectors and the unit/station transformer feeds over the majority of their routes up to the cable race immediately below the switchgear. Similarly, where auxiliary transformers and feeders are duplicated within a unit, segregation can often be achieved for the majority of the cable routes without additional cost. Other circumstances where segregation should be applied if there is no cost penalty are main and standby plant, and also between boiler feed pumps where more than one is provided per unit. Separation should be provided between control cables (containing analogue signals, digital signals or 430
Chapter 6
plant protection signals) and power cables to minimise the effects of electrical interference. Control cables should be separated from single-core power cables by at least 600 mm and from muiticore power cables by at least 300 mm. This requirement does not apply to tail ends of routes where power and control cables are terminated in the same equipment, providing the length of run where separation distances are not met does not exceed 5 m. The basis for these electrical separation distances is discussed in Section 5 of this chapter. 2.1.2 Segregation requirements for nuclear power stations
The segregation requirements for conventional power stations to protect availability of plant are equally applicable to nuclear power stations. However, in nuclear power stations additional segregation is necessary for the safety of personnel, the
general public and plant. For these additional segregation requirements the occurrences considered are minor fire, safe shutdown earthquake (SSE), local flooding and a major incident within the station, i.e., turbine disintegration, major fire or hot gas release. The safety criterion normally applied is that any one of these incidents and its consequential effects shall not damage sufficient safety related cables to render the reactor trip and post-trip functions ineffective to a degree where an unacceptable probability of a district hazard would arise. In practice, this means that: • The reactor must retain its ability to trip. • A specified proportion of the post-trip cooling, monitoring and control systems must remain effective. • Consequential faults must not degrade the effectiveness of the reactor trip system or post-trip cooling systems, e.g., gas circulator run-on. The method of applying these criteria will depend on the type of reactor involved. However, to illustrate the principles, an advanced gas-cooled reactor (AGR) will be considered. Firstly we must elaborate on the meaning of segregation and for this it is convenient to define two segregation classes. Segregation Class I is defined as 'cables, plant or equipment of different groups that must be separated by a barrier or enclosure having a minimum of four-hour fire rating and also be crash proof to the required standard for the safety hazard at the barrier/enclosure location'. Segregation Class II is defined as 'cables, plant or equipment of different groups that must be separated by a minimum of onehour fire barrier or enclosure'. For cables installed direct-in-ground, cable groups should be separated by at least four metres for Class I and by at least one metre for Class II. The larger separation distance in-ground for Class I is in order to avoid accidental
Cable systems arid layout damage to both groups by mechanical excavations. for segregation Classes I and II where cables are laid in troughs, the routes for cable groups should be ,eparated by at least six metres to protect against oil or mechanical damage. dditional segregation in an AGR is associated The a „iih safety related cables. Safety related cables are :hose which contain cores/pairs which can effect the tion, operation or termination of: init i a fety related fault prevention actions (e.g., control • sa rod interlocks). •
Reactor trip and shutdown actions.
• Post-trip actions. Cables associated with plant protection, indication or alarms which in the event of a fire are essential to operator in the central control room, emergency an indication centre or local control position are also Liesignated safety related. This includes fire fighting ,ervices and essential station communications. A fur:her special function is heating and ventilation services for contaminated areas. The segregation of safety related cables is considered in the following section. However, the following rules are only written for areas outside the confines of the safety room. Cabling, conduits and trunking within the confines of the safety room are subject to special requirements, and these are considered too specialised o include in this volume. Solely
related cables excluding reactor safety trip
s%cterns
This section deals with the segregation of safety relaR;(1 cables with the exception of reactor safety trip .stems which are a special case. Safety related cables ■■ [II be discussed under three broad headings: • Power cables
The Heysham 2 power system arrangement for one reactor is described in Chapter 1 and shown in Fig 6.1. The electrical trains forming the essential electrical system are broadly associated with the boiler circulator quadrants (A to D) of the reactor, and provide power supplies for two post-trip cooling systems. These two post-trip cooling systems are designated X and Y. Essential cooling system X is associated with forced gas circulation, e.g., gas circulators and forced-feed decay heat boilers. Essential cooling system Y is associated with natural gas circulation and emergency feed to the main boilers.
Segregation must be employed to limit damage to the cables providing supplies to the plant and auxiliaries associated with the X and Y cooling systems. Two rules have been formulated to define the segregation to be employed, depending upon the type of incident to be protected against.
In the case of more probable incidents, such as a small fire, segregation must be employed to ensure that no more than the X and Y supplies of one quadrant become unavailable. Another option is that not more than half the total X system or, alternatively, half the total Y system supplies become unavailable. To meet this rule, Class II segregation is required between quadrants or between halves of systems. In the case of less probable incidents, which are those liable to cause most damage such as turbine disintegration or a major fire, a different set of segregation rules must be applied. It is required that no single incident of this type causes damage to such an extent that both the X and Y cooling systems become unavailable to more than two reactor quadrants. Another option for this type of incident is that not more than all the X system supplies or, alternatively, all the Y system supplies fail. Thus, for a major incident, Class I segregation is required between quadrant pairs A B and C D and their associated trains, or Class I segregation is required between complete sections of the X and Y systems. In addition, separation shall be provided between the X system and Y system power cables associated with the same quadrant, and between power cables associated with different quadrants routed to and within system plant areas segregated on a half system basis. It is not mandatory to separate safety related power cables from other power cables except to ensure that the segregation principles have been maintained. • Control cables
The segregation specified for safety related power cables is also applied to the associated control cables where these are required in the performance of the safety related function. This applies to post-trip sequence control signals to essential plant. There is no need to segregate control cables from associated power cables to the same equipment. However, it is prudent to separate them to reduce electromagnetic interference as defined for conventional plant. There is no special requirement to separate safety related control cables from other control cables associated with the same train. Typical post-trip cooling system and safety trip system cabling is shown in Fig 6.2.
• Cables for remote control and indications associated with safety related plant and equipment In
the central control room (CCR), area segregation of control and indication cabling between trains/ quadrants is provided to Class II. This segregation is provided to limit economic damage and is not necessary for reactor safety for the following reasons: (a) While the reactor is at power it is protected against rapidly developing faults by safety cir431
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DIVERSE GUARD INES OLD ENO CONTACTORS
14
1
NOTE TORT SE FEEDS
CCA MANUAL TRIP DX
EIC MANUAL TRIP
-- SAFETY TRIP GROUPS
SAFETY TRANSDUCERS VIA PILE CAP
QUADRANT AREAS
SEGREGATION OF CLASSI BARRIER OR COMBINATION OF CLASS II BARRIERS A SEGREGATION OF CLASS 2 BARFBER SAIL IV I HAN,ATUL.1 TTS
1 kAiN CABLE HOWES
FIG. 6.2 Typical control cabling for a reactor safety trip system and post-trip cooling system
lnoAel pue swelsAs alqeD
1
OY
B.B11121112.NBALid
1 PILE CAP AND TURBINE HALL CABLING IS NOT SEGREGATED INCLuCANG COO TEMPERATURES AND FLUX HEASURENEN I S
Cabling cuits and against slowly developing faults by the CCR operator.
metal armouring or are run in earthed metal conduit.
(b) When the reactor is tripped, post-trip cooling is automatic. The possibility of spurious control signals from the CCR which could prevent effective cooling is inhibited by automatic disconnection at the switchgear/equipment remote from the CCR.
(b) Class II segregation between pairs of safety channels of the same trip group.
Displays associated with public hazard are normally duplicated with one display in the CCR and the other in the emergency indication centre (EIC). Cables associated with these duplicated displays should be segregated from each other to segregation Class II. As far as the cabling to the EIC is concerned, segregation to Class II is provided between each unit. For each unit, cables associated with quadrants A and B are separated from cables associated with quadrants C and D.
Cables associated with reactor safety trip systems Typical post-trip cooling system and safety trip cabling is shown in Fig 6.2 and, as can be seen, the reactor tripping hardware is provided on a multichannel (guard-line) fail-safe basis. The circuits are normally energised so that if the cabling associated with a particular guard-line is damaged, that guard-line will fail-safe. Outputs from a safety group provide the inputs to guard-line equipment where they are reviewed on a redundant voting (e.g., 2 out of 4) basis. Outputs from all safety groups provide signals to each of four main guard-line (MGL) equipments which produce the necessary signals to initiate the reactor trip cooling systems. Outputs from particular safety trip groups (e.g., gas temperature) also provide signals to each of four diverse guard-line (DGL) equipments, which produce additional signals to initiate the reactor trip systems. Outputs from the MGL and DGL equipments also provide signals to the secondary shutdown initiation (SSE) equipment. The outputs are reviewed on a redundant voting basis (e.g., 2 out of 4) in each of four channels. If the primary shutdown rods do not insert adequately, the SSI, MGL and DGL equipment provide signals on a guard-line basis to operate the secondary shutdown (SSD) nitrogen injection valves. The SSI equipment also provides signals to separately initiate the reactor post-trip cooling systems and to remove control rod clutch power supplies at the source. Signals associated with reactor safety trip systems are run in cables separated from all other signals. Cables carrying safety trip systems are subject to the following segregation, separation and special requirements: (a) Except for special cable requirements such as flux systems, all safety trip system cables have earthed 434
Chapter 6
(c) Class 11 segregation together with a 2 m separation distance between safety channels of the same trip group. (d) Safety system cables are separated from singlecore power cables by at least 600 mm and from multicore power cables by at least 300 mm. This requirement does not apply on plant or equipments at which the cable ends are terminated, provided that, for any safety system cable, the summated total of all the lengths of such cable run in parallel with power cables at less than the above stated separation distances, does not exceed 5 m. (e) Safety system cabling carrying very low signal levels, e.g., neutron flux measurement signals, should be separated from single-core power cables by at least 600 mm and by at least 300 mm from all other cables. This requirement is applicable to the gland-to-gland route length of the cables. (f) Separate earthed armoured cables are provided for incoming signals to the guard lines and output signals to the shutdown system. Input signal cables must be separated from output signal cables, and the routing of these cables is normally subject to special approval. (g) All safety system cables are marked on each core at each termination with an orange ferrule, in addition to other identifying symbols. (h) Except for cables carrying very low signal levels as (e) above, reactor safety trip system cables associated with safety channels are not required to be segregated or separated from other control cables. All reactor safety trip system cables, however, are routed along dedicated cable tray modules (which are separate to cable tray modules for other control cables) and they must be clearly identified by orange coloured bands at 1 m intervals. Groups of reactor safety trip system cables may be identified by a common orange coloured band. Conduits and trunking are similarly identified. (i) All reactor safety trip system cables are: • 2.5 mm 2 multicore cables of the type described in Section 3.5 of this chapter, or • 0.5 mm 2 (1/0.8 mm dia.) muItipair cables of the type described in Section 3.6 of this chapter, Or
• Special cables for thermocouple or neutron flux instrument signals.
Cable types
Where a plant contact is being monitored for use in a safety trip system, the cabling to the plant contact is designed to prevent the occurrence of a fail-danger fault due to a short-circuit between the go and return cable cores. Cable designs which use cables having individually screened cores are acceptable. Separate cables for each go and return lead should not be used. (k)
The use of marshalling is avoided unless essential.
2,1.3
General layout requirements
From this section so far, it will be evident that se.,regation requirements for electrical plant and cables have a considerable impact on station layout. Segreuation requirements must therefore be considered early in the station design and one of the best ways of assessing problems is by the use of an isometric drawing. Figure 6.3 is an isometric drawing for an AGR station and, as can be seen, a different colour is used for each segregation class. Scale models can also be used to assess segregation provisions. Such models are also particularly useful later in the design of cable installations to check for fouls with other services, such as pipework. When considering layout, the importance of the cable installation programme must be fully recognised. Cable accommodation must be made available in good ti me and cable tunnels or basements have advantages from this point of view since they are at the bottom of the building and must, of necessity, be scheduled early in the civil programme. If cable basements cannot be economically justified due to civil engineering considerations then, as an alternative, dedicated overhead cable routes should be provided. Dedicated cable routes are considered essential to avoid disruption of the cable installation programme due to access being restricted by other contractors. Overhead cable routes are generally very successful in boiler houses, but for turbine halls they are more difficult because the plant is more compact and its erection involves the turbine hall crane. It is difficult therefore to obtain unrestricted access to install the cables which leave the overhead route. However, main overhead routes do have the advantage that they can support other services, but once again care must be taken that the installation of such services does not restrict access for cable installation. When designing cable routes it must be recognised that cables are pulled - off cable drums and it is therefore essential that provision is made for cable drum access, normally at one end of the route only. Where possible the cable drum position should be at the highest route point to reduce pulling tensions. further point to consider is the separation of major cable termination facilities, such as those in the CCR, from cable routes since this allows better access to terminations and, in addition, allows a higher
level of illumination to be provided economically for
terminating work. As discussed in Section 2.1.1 of this chapter, major cable routes should be enclosed to provide the required segregation and prevent release of smoke into operational areas should a cable fire occur. Access and emergency exit points must be provided for these enclosed routes. The distance between emergency exits is normally controlled by local regulations and premises have to be covered by a Fire Certificate which may be issued either by Fire Officers or the Health and Safety Executive, depending on the type of premises. For power stations, the maximum distance between escape points should be 45 m and the provision of these must be considered early in the cable system layout. For long enclosed cable routes, it is sensible to provide fire barriers at regular intervals across the tunnel to restrict damage in the event of fire. If these barriers are spaced at the distance required for emergency escape points, then the door through the barrier will form an escape point from a fire-affected compartment to a safe area. Major cable routes should be protected by a fixed waterspray fire protection system and therefore the floor areas should be tanked, and drainage provided.
3 Cable types The first part of this section deals with cable constructions that are currently in common use in power stations. These cable types all contain polyvinyl chlo-
ride (PVC) and are designed to meet the reduced propagation performance detailed in Section 8.2 of this chapter, but there has been no deliberate attempt to reduce smoke, acid or toxic emissions. Such emissions are dealt with using the fire protection requirements detailed in the previous section. Recent developments are producing limited fire hazard cables which have the same reduced propagation performance, but in addition have lower noxious gas emissions; a general overview of these cable types is given at the end of the section. Before looking at detailed cable constructions it is necessary to consider some of their basic components. Firstly we should consider cable conductor material. Ignoring special applications, the choice is basically between copper and aluminium. Aluminium conductors with a cross-sectional area of less than 16 mm 2 have proved from experience to be very difficult to terminate, because of the tendency for aluminium to 'cold flow' when put under pressure in, say, a standard screw type terminal. Copper is therefore used for power cable conductors of cross-sectional area less than 16 mm 2 and for control cables. For cables having a conductor size of 16 mm 2 and greater, the choice of conductor material is mainly a question of economics. Aluminium has a higher electrical resistivity than copper and to achieve comparative voltage drop and current rating 435
■...„ OIESEL HOUSE ..L
KEY
I
I
TRAIN A TRAIN
1
e
TRAIN C
ESSENTIAL SUPPLIES BUILDING
CABLE TRAINS FOR ESSENTIAL ROU IFS (ESSEN 11AI SUPPLlt S CONCERNING 1 HE QUADRANTS)
TRAIN 0 CABLE FLAT
NON E SSEN FIAL ROUTES ( GENERAL PURPOSE USE) FIRE BARRIER CLASS FIRE BARRIER CLASS II
DIESEL HOUSE ESSENTIAL SUPPLIES BUILDING
CABLE FLAT
FIRE BARRIER CLASS I
DIESEL HOUSE TUNNEL ESCAPE k
IN I I AL
SuPPL II S DUlL CANUS
ESSENTIAL AUXILIARY TRANSFORMER 1FIX
DIESEL HOUSE STATION TRANSFORMER
FIG.
kSSI NTIAL AuXILAHy T HAN S I URMEFI l AX
6.3 Isometric drawing showing segregation provisions for an AGR siation
Cable types n aluminium conductor has to have in the order of 1.6 times the cross-sectional area of a copper conductor. However, the specific gravity of aluminium is approximately one-third that of copper, so after taking into account the relative resistivities, the weight of an aluminium conductor would be approximately half that of copper for comparative duties. The relative ,.:osts of cables cannot be assessed on the weight of conductor material and its cost per tonne since a larger aluminium conductor results in additional insulation, armouring and sheathing materials. Because aluminium has ueater ductility than copper, solid aluminium conductors can be used in many applications and these are cheaper to produce than stranded conductors, and form a more compact cable. When assessing conductor material it is important to take into account the relative cable weights and dimensions which will affect Installation and cable support structure costs. The relative costs of aluminium and copper cable installations have varied over the years, but the considerable price advantage and improved methods of terminating resulted in the use of aluminium cables becoming established in power stations in the early 1960s. Since that time, the cost of aluminium has increased steadily vith the cost of energy, which is a dominant factor in its production. Copper, on the other hand, whilst having fluctuated in cost has not seen a large overall increase. The cost differential between aluminium and copper cables has therefore narrowed, but aluminium cables remain competitive for the majority of power applications within power stations, and are not subject to the price fluctuations associated with copper. A further general topic is to consider the nature of polymeric materials that may be used for insulation and sheathing of cables. In the cable industry, the term polymeric material is a general term used to embrace plastics and rubbers. Rubbers are also frequently termed elastomers. Polymerics can be further classified into thermoplastic or thermosetting materials. Thermoplastic materials are those that can be softened by heating and hardened by cooling, i.e., they can be moulded and remoulded any number of times. The most frequently used thermoplastics are polyvinyl chloride (PVC) and polyethylene (PE). Thermosetting materials, on the other hand, do not soften to any great degree below their decomposition temperature and therefore are not capable of being remoulded. Many thermoplastic materials can be turned into thermosets by 'cross-linking'. The process of cross-linking or vulcanisation consists of forming chemical bonds between the long chain molecules to give a 'ladder' effect which restricts slippage between molecules and lproduces good thermal stability. The process of crossinking can be achieved by high energy radiation or by chemical methods. Chemical cross-linking is the traditional method for the production of cables, but radiation cross-linking is increasing in popularity for Wires and small cables where insulation thicknesses are not excessive. a
The most common method of cross-linking is by the addition of an agent such as peroxide to the polymer which can be activated by heat. The crossli nking agent is introduced into the polymer prior to it being extruded onto the cable. It must therefore be selected such that it is inactive at the extrusion temperature (typically 120-130 ° C). To activate the crosslinking process the polymer is normally raised to a temperature of about 200 ° C. During the curing process, gaseous decomposition of the cross-linking agent occurs and to avoid porosity of the polymer a high pressure is maintained around the insulated conductor. The curing process is carried out by passing the insulated conductor immediately after extrusion into a continuous vulcanisation line, in which the required heat and pressure for the curing process is provided. This vulcanisation line consists of a pipe attached directly to the extruder head, which is filled with high pressure steam or inert gas. After vulcanisation has been achieved in the heated portion of the pipe, the insulated core is cooled by passing through water at ambient temperature at the exit end of the pipe. An alternative form of chemically cross-linking materials is to use a silane compound to form the links between the long molecular chains. This cross-linking method does not require heat or pressure, but is activated by moisture in the presence of a catalyst, this normally being carried out by immersion in water at a temperature of 80-90 ° C. This curing method is more competitive since it avoids the expense of continuous vulcanisation lines. Examples of thermosetting materials used for insulation are cross-linked polyethelene (XLPE) and ethylene propylene rubber (EPR). Cables produced from thermoplastic materials such as PVC are cheaper, size for size, than those made from thermosetting materials because of the expensive plant and curing time associated with the latter. However, cables manufactured with thermosetting insulation generally can operate at higher temperatures (both continuous and short-circuit). This may result in a reduction in conductor size and hence an overall cost saving. For example, PVC-insulated cables are normally assigned a continuous conductor operating temperature of 70 ° C and a short-circuit temperature of 160 ° C, compared with 90 ° C and 250 ° C respectively for thermosetting materials such as XLPE and EPR. Finally, it is worth noting that it is normal practice to separate power and control cables to reduce electromagnetic interference and, to enable this separation to be checked on site, power cables have black sheaths whilst control cable sheaths are coloured grey.
3.1 11 kV cables For II kV cables, the choice of insulant rests between paper or polymeric. Paper insulated cables have lead or alloy sheaths and in consequence are heavier and more difficult to install and terminate than plastic 437
Cabling
Chapter 6
insulated cables. More importantly, plastic insulated cables can be made considerably more fire retardent than paper cables and therefore plastic cables are selected for power station applications. The design and testing of such cables with solid extruded insulation is specified in Generation Development and Construction Division (GDCD) Standard 17 which covers single-core cables having cross-sectional areas of 300 mm 2 and 500 mm 2 . Single-core cables are selected primarily because of the fault levels associated with power station 11 kV systems. Since circuitbreakers are used for switching, the fault current is not restricted as it might be at lower voltages where fuses are employed in many instances. For 11 kV, 750 MVA fault rated systems, the RMS symmetrical value of fault current for phase faults is 39.4 kA, with a first peak as high as 121 kA. The electromechanical forces associated with such currents could result in three-core cables 'bursting', i.e., the outer coverings of the cable being torn open by the repulsive forces between the conductors. A further item to be considered is that it is normal practice to earth the neutral of 11 kV systems via a neutral earthing resistor, which will restrict the earth fault current per feed to approximately 1 kA. Under these circumstances it is quite clearly worthwhile taking steps to avoid phase faults, which can be extremely destructive. The use of singlecore cables means that any faults that occur within the cable must be between conductor and the screen (or armour) which is earthed, hence the fault current will be restricted by the neutral earthing resistor. Finally, the resistive heating effect in the conductor under short-circuit conditions dictates a minimum conductor size that would render three-core cables physically large and heavy for installation. The construction of single-core cables with solid extruded insulation is given in Fig 6.4. The preferred
insulation is of the thermosetting type, i.e., XLPE or EPR, which gives a conductor continuous operating temperature of 90 ° C and a short-circuit temperature of 250 ° C. Thermosetting materials give significant benefits since the size of 11 kV cables is frequently dictated by short-circuit requirements, indeed the minimum aluminium conductor size of 300 mm 2 normally prescribed in power stations is derived from this consideration. For comparable duty, a paper insulated cable having a maximum short-circuit temperature of 160 ° C would require a minimum aluminium conductor size of 400 mm 2 . The electrical stress in the insulation for these cable designs is in excess of 2 kV/mm and this necessitates the use of conductor and core screens for stress control. Figure 6.5 shows the stress distribution in a well screened cable where the exponential lines are concentric and the flux lines are evenly distributed. Figure 6.6 shows the stress distribution for a cable without a conductor screen, and here it can be seen that the equipotential lines are deformed and become bunched together at the protruding conductor strands, giving high electrical stress in the insulation at these points. Such high stresses may cause a local breakdown in the insulation known as a partial discharge, which can cause erosion of the dielectric and ultimately complete breakdown of the cable. A similar situation can occur on the outer surface of the insulation and Fig 6.7 shows the effect of an incomplete core screen. The conductor core screen normally consists of an extruded layer of semi-conducting material frequently applied over a semi-conducting support tape, which prevents the extruded material being 'lost' between the conductor strands. The insulation screen may be either an extruded layer of semi-conducting material or a semiconducting varnish applied direct to the insulation surface, with a semi-conducting tape applied over it
OVERSHEATH
BEDDING INSULATION SCREENING SEMI.CONDUCTING CONDUCTOR SCREENING
CONDUCTOR INSULATION METAL SCREEN WIRE ARMOUR
FIG. 6.4 11 kV single-core cable construction
438
Cable types
CONDUCTOR SCREEN
INSULATION SCREEN
FIG. 6.5
Stress distribution in cable insulation
EOUIPOTENTIAL LINES
Fic. 6.7 Stress distribution with section of core screen missing
of aluminium armour wires, these being non-ferrous to avoid eddy current heating, and finally a PVC outer sheath. It is important to ensure outer sheath integrity to prevent water entering the cable and because the cable armour will have standing voltages due to single-point bonding of the armour (see Section 11 of this chapter). A semi-conducting layer is therefore applied to the outer sheath to allow effective electrical testing between this and the cable armour to demonstrate sheath integrity.
3.2 3.3 kV cables FIG. 6.6
Stress distribution in cable without a conductor screen
as protection against mechanical damage from the metallic screen. Where extruded screens are used, these should be 'cold strippable' to ease the process of terminating. A helically-applied copper tape screen is provided over the semi-conducting insulation screen to carry both leakage and fault currents. The copper tape is designed to carry an earth fault current of 1 kA for one second. A PVC inner sheath is provided over the copper tape to provide a bedding for the armour wires. This inner sheath also performs the important function of a secondary moisture barrier to prevent
water reaching the primary insulation in
the event of the outer sheath being damaged. The
cable construction is completed by applying a layer
3.3 kV systems in modern power stations can have a fault level of up to 250 MVA, which gives a phase fault current of 43.7 kA, and neutral earthing resistors are fitted to restrict earth fault currents to 1 kA per feed. The situation is therefore similar to that for 11 kV described in the previous section, and single-core cables are again prescribed for 3.3 kV circuit-breaker fed equipment. This type of application frequently consists of short tails of cable from transformer to switchgear, where full advantage can be taken of the higher continuous operating and short-circuit temperatures of thermosetting materials. Such single-core cables are purchased to the general requirements of IEC 502, the constructional make up being shown in Fig 6.8. A stranded aluminium conductor with a minimum cross-sectional area of 400 mm 2 is required to meet the short-circuit requirements detailed above, and this size will normally be adequate for all applications. The insulation consists of XLPE 439
Cabling
Chapter 6
Ov E RS H E A TH
WIRE ARMOUR
Ftc. 6.8 3.3 kV single-core cable construction
or hard ethylene propylene rubber (HEPR) having a radial thickness of 2 mm. The cable is finished in a si milar manner to that for 11 kV by applying a PVC inner sheath, aluminium wire armour and PVC outer sheath. Once again, a semi-conducting coating is applied to the outer sheath to facilitate electrical testing. In the interests of switchgear economy, circuits such as motors and small transformers are fed from fused switching devices (FSD) wherever possible. As described in Chapter 5, a fused switching device consists of a s mall circuit-breaker capable of interrupting up to about 10 kA which is protected from higher fault currents, by fuses. Whilst these fuses are provided primarily to protect the switching device and ensure satisfactory short-circuit fault clearance, they also provide protection to the circuit cables attached to them. Because
EXTRUDED OVERSHEATH
the fault current is 'cut-off', the short-circuit power and electromagnetic forces are reduced allowing three-core cables to be used. Under these conditions, thermosetting insulation offers no significant cost advantage over thermoplastic insulation. Three-core cables suitable for this application are detailed in BS6346 and the constructional arrangement is shown in Fig 6.9. The conductors are solid shaped aluminium and cross-sectional areas of 150 mm 2 and 240 mm 2 are normally adequate for power station applications. The minimum cable size of 150 mm 2 is related to a fuse size of approximately 400 A which is the maximum fuse rating for a FSD. The 240 mm 2 size is considered adequate to handle the largest size of load that can be connected to a FSD. The insulation, inner and outer sheaths consist of extruded layers of
ALUMINIUM STRIP ARMOUR EXTRUDED INSULATrON
CONDUCTOR EXTRUDED BEDDING
FIG. 6.9 3.3 kV multicore cable construction
440
Cable types p VC. The armour on these cables is aluminium strip improve conductivity, since it is used as an earth to fault current return path, as discussed in Section 11.5 this chapter. These three-core cables have a maxiof m continuous conductor temperature of 70 ° C and mu maximum short-circuit conductor temperature of 3
I 60 ° C. 3,3 415 V cables Sinde-core cables are selected for use on equipment ,:ontrolled by circuit-breakers. Once again the insulant selected for these single-core cables is XLPE or EPR ° ,,ince advantage can be taken of the 90 C continuous ° and 250 C short-circuit temperatures. The construction and dimensions of these cables are identical to those for use on 3.3 kV systems. Once again a rationalised 2 conductor size of 400 mm stranded-aluminium will be found suitable for short-circuit requirements and all normal full-load current applications. Multicore cables are selected for use on fuse proieLL:ted circuits. On 415 V fuse protected circuits, the Li miting criterion for cable sizing is frequently voltdrop and therefore no advantage can be taken of the hi der operating temperature of thermosetting insulati ons; 600/1000 V thermoplastic insulated cables complying with 856346 are therefore specified. For cable sizes 16 mm 2 and above, the conductors are solid aluminium, these being circular for the 16 mm 2 size and shaped for larger sizes. The cables have extruded PVC insulation, a taped PVC inner sheath, aluminium strip armour and extruded PVC outer sheath. For cable sizes of less than 16 mm 2 , circular strandedcopper conductors are used covered with extruded PVC insulation, extruded inner sheath, steel wire armour and extruded outer sheath. To ease bulk ordering and )tocking difficulties a rationalised range of cable sizes Ls shown in Table 6.2. Aluminium strip armour has been selected for the larger cable sizes because it is utilised as the main
TABLE
6.2
Raiionalised range of cable sizes
Conductor CSA, mm 2
Number of cores
Construction
2.5
2, 3 and 4
Cu/PVC/PVC/SWA/PVC
4
2, 3 and 4
Cu/PVC/PVC/SWA/PVC
6
2, 3 and 4
Cu/ PVC/PVC/SWA/PVC
16
2, 3 and 4
AI/PVC/PVC/ALS/PVC
35
2, 3 and 4
AI/PVC/PVC/ALS/PVC
70
2, 3 and 4
AI/PVC/PVC/ALS/PVC
120
3 and 4
Al/PVC/PVC/ALS/PVC
185
3 and 4
AI/PVC/PVC/ALS/PVC
300
3 and 4
return path for earth fault currents. Whilst the armour of the small copper cables is also utilised for the earth fault return path, the smaller fuse sizes associated with these circuits allow steel wire armour to be specified. 3.4 Cables for DC power circuits The cables detailed in the previous section for 415 V AC circuits are also suitable for use on DC circuits. The largest two-core cable listed in the rationalised cable range given in Table 6.2 is 70 mm 2 . Where crosssectional areas in excess of this size are required, it is normal practice to use a four-core cable with its cores paralleled such that two cores are used for each pole. 3.5 Multicore control cables Multicore control cables suitable for use in power stations are manufactured to ESE Standard 09-6, Section 1. These come in a range of sizes from two-core up to 37-core and are rated at 600/1000 V. These cables consist of a 2.5 mm 2 (7/0.67 mm dia.) stranded-copper conductor with PVC insulation. The required number of cores is then laid-up with an overall plastic binder tape, extruded PVC inner sheath, steel wire armour and PVC outer sheath. The cores are numbered for identification purposes. The steel wire armour is provided for mechanical protection and to improve the reduced fire propagation performance. 3.6 Multipair control cables Multipair control cables are manufactured and tested to the requirements of GDCD Standard 200 in a range of sizes from two-pair up to 200 pairs. These cables use plain solid annealed-copper conductors having a cross-sectional area of 0.5 mm 2 (1/0.8 mm dia. wire), which are insulated with an extruded layer of PVC. Two insulated cores are twisted together to form a pair and then pairs are laid-up to form the required cable size. The two-pair cable does not actually consist of two pairs, the four cores being all laid-up together in what is known as a quad formation. For cables having greater than 20 pairs, a unit construction is used. This means that the cable contains a number of 20-pair units, each 20-pair unit having the same colour coded core sequence, and a numbered binder tape to enable one unit to be identified from another. The colour code is in accordance with IEC Standard 189.2. An overall screen is applied over the laid-up pairs and in the case of 5-pair and larger cables this is formed from a longitudinally-applied aluminium laminate. A tinned-copper 'drain wire' is provided under and in contact with the aluminium screen, to enable it to be connected to earth. An extruded inner sheath is applied over the screen which strongly adheres to the plastic backing of the aluminium laminate. Cables containing 20 pairs and greater are armoured using 441
Cabling double-galvanised steel tape armour. Steel wire armour is used for 2, 5 and 10-pair cables which are too small in diameter for steel tapes to be applied. The cables are sheathed overall with an extruded layer of PVC. The range of cable sizes includes 2, 5, 10, 20, 40, 60, 100 and 200 pairs. These cables are suitable for use at voltages up to and including 110 V AC or 150 V DC. The aluminium laminate screen provides a moisture barrier to prevent ingress of moisture to the cores as well as being an effective screen against higher frequencies. The steel tape armour provides power frequency screening.
Chai. The first category covers 'digital' type detectors a general arrangement of one of these is shown Fig 6.10. These generally consist of two steel wire COI ductors that have been insulated with a suitable ther moplastic material and twisted to form a pair. At th,
5TEE
WIRE
THERMOPLASTIC
3.7 Short - ti me fireproof cables A short-time fireproof (STFP) cable is one that, under test conditions, will remain serviceable for 20 minutes when exposed to a flame temperature of 1000 ° C. These STFP cables are available as both multicore and multipair designs, their construction and testing being specified in GDCD Standard 195. The multicore design has 2.5 mm 2 (7/0.67 mm) stranded-copper conductors laid-up in 2, 3 and 4 core cable constructions. The multipair design has 0.5 mm 2 (1/0.8 mm dia.) solid copper conductors laid-up into 2, 5 and 20 pair constructions. The detailed cable construction is not standardised as manufacturers like to use their own special designs. However, all cables are required to be steel-wire armoured and sheathed for mechanical robustness. The electrical performance of these special cables is required to be equivalent to the standard cables detailed in Sections 3.4 and 3,5 of this chapter. The special fire performance of these cables is achieved by appropriate primary insulation. Examples of materials that can be used are silicone rubber or ethylene propylene rubber in conjunction with mica tapes or glass braid. These types of cables are expensive compared with conventional cables and their use has therefore to be li mited. Typical applications are selected trip and protection functions, audible warnings and communication circuits that it is essential to keep in service under fire conditions.
3.8 Linear heat detecting cables With the growing concern regarding the considerable damage that can occur to power station installations under fire conditions, means of rapid fire detection have been sought. Linear heat sensors in the form of cables which can detect relatively small increases in temperature are one solution. These are particularly effective for fire detection in cable routes when a linear heat detecting cable (LHDC) is mounted over each cable tray. Linear heat detecting cables are manufactured and tested to the requirements of GDCD Standard 187 which covers two different types of sensors. 442
TAPE
OUTER COVERING
FIG. 6.10 Digital-type linear heat detecting cable
set operating temperature the thermoplastic softens, allowing the steel conductors to move and short-circuit. Different operating temperatures can be obtained by small variations in the cable design. The short-circuit that occurs at the set operating temperature can be used to initiate alarms or fire protection systems. The second category covers 'analogue' type detectors and a typical arrangement is shown in Fig 6.11. In this type of detector, the insulation is specially formulated to have a rapid rate-of-change of resistance with temperature. The resistance of the detector is monitored and any change beyond a set point relating to the required operating temperature is used to trigger the required alarm or fire protection systems.
3.9 Developments in cable design The current awareness of noxious gas emission from cable fires has brought about a rapid development in cable compounds to replace high halogen content materials such as PVC. Cables constructed with these new compounds are generally known as 'limited fire hazard' designs. Suitable fire tests to assess reduced
Cable types
pruy- Fc TIRE SHEATH
TEMPERATURE SENSITIVE DIELECTRIC MATERIAL
CROSS SECTION OF DETECTOR CABLE
with a continuous conductor temperature of 90 ° C and a short-circuit temperature of 250 ° C, smaller conductor sizes can therefore be used than would be required if PVC insulation were used for the same duty. For multicore control cables, PVC primary insulation is generally being replaced by a dual layer of EP R/ EVA. The layer of EPR provides the required electrical performance whilst the outer layer of EVA gives sufficient fire performance to pass the test on a single insulated wire, which is detailed in Section 8 of this chapter. For multipair control cables, the PVC insulation is being replaced by high performance thin-wall insulations such as polyphenol oxide (NORYL — a General Electric (USA) trade name) and poly ether ether ketone (PEEK — an Imperial Chemical Industries trade name). Both these materials are thermoplastic but in the case of PEEK, cables insulated with this material are capable of operating at temperatures in excess of 250 ° C under defined conditions. However, at the time of writing, these materials are considerably more expensive than PVC. One of the difficulties with these developments is that the material formulations are new and there is little service experience with them compared to PVC which has been used for over thirty years. Therefore it is essential that cables employing such new materials are adequately evaluated before putting them into service; the remaining parts of this section define tests that are used for this purpose.
3.10 Thermal ageing PROTECTIVE SHEATH
FIG. 6.11 Analogue-type linear heat detecting cable
propagation performance and reduced gas emissions are given in Section 8 of this chapter.
The basic construction of cables has remained the same but new compounds have been substituted for
PVC. For cable beddings and sheaths, currently the inost commonly used replacement for PVC is ethylene vinyl acetate copolymer (EVA). EVA is available in both thermoplastic and thermosetting forms. For thermosets, curing can be achieved by continuous vulcanisation by steam or pressurised liquid, and also by immersion in hot water if the silane compound method has been used. These materials are filled with
alurninituirt hydroxide to give reduced fire propagation performance Whereas PVC has been used in the past for primary insulation on power cables, this is generally being changed to ethylene propylene rubber (EPR) or crosslinked polythene (XLPE) which has hitherto only been used on single - core power cables. Thermosetting EVA is also being used in some cases for power cable insulation. All insulation materials are suitable for use
For normal service life, one of the significant degradation processes in cables is the ageing of their non-metallic materials. It is therefore important to evaluate cables to ensure that they can operate at the required temperature for their service life. For many non-metallic materials the degradation process can be defined by a single temperature-dependent reaction that follows the Arrhenius equation: K = Ae
(-Ea1'k13T)
(6.1)
where K = reaction rate A = frequency factor = 2.718 E a = energy needed to activate the degradation reaction (electron volts) kB = Boltzmann's constant (8.617 x 10 -5 eV/K) T = absolute temperature, K This can be transferred into a form which yields an acceleration factor, defined as the service life divided by ageing time, as follows: 443
Cabling
Chapter 6 12
,
C
[- E
k E1( 1.11-
— I
7- -
1
(6.2) MARKER LINES lOmm
ti
where T i
accelerated ageing temperature, K
R7 51,m,
normal service temperature, K :
tI
= accelerated ageing time at temperature T1, years
t2
= accelerated ageing time at temperature T2, years
3 5,,
!
3mm
• Power cables — 75 ° C mean. ° (90 C maximum continuous rating) • Power cables — 55 ° C mean. ° (70 C maximum continuous rating) — 40 ° C mean.
It is normal practice to take the service time as the design life of the power station. This may vary from 25 years to 40 years, or 50 years for hydro stations. It is considered good practice to ignore reduction in service life due to maintenance outages or two shifting during the later years of conventional plant, as this allows some margin in the predicted life of the cables. -
Having defined the service conditions it is now necessary to establish the activation energy of all essential non - metallic materials within the cable. The term essential is used since, for example, some binder tapes are included in cables purely for manufacturing purposes and therefore if they failed mechanically they would not affect service life. The activation energy of non-metallic materials may be determined by carrying out ageing tests on samples at a number of temperatures. A typical criterion for ageing performance evaluation is to assess the time it takes for the material's 'elongation at break' to reduce to occur at 1.5 times its initial length (50 070 absolute). Dumb-bell samples, of the type shown in Fig 6.12, are therefore used and these are aged in circulating air ovens. Samples are aged at a number of temperatures (say four), these being at least 10 ° C apart and with a maximum temperature of (typically) 444
R107/
50,11
To apply this formul a, the service temperature and required life of the cable must be defined together with the activation energies of the materials involved. As far as service temperature is concerned, this should be the estimated average service temperature over the life of the cables. For example, cables are generally sized against maximum ambient conditions which allow for peak summer temperatures and the least effective air conditioning. In reality this means that a cable capable of working at a maximum continuous operating temperature of, say, 90 ° C may in fact be operating at an average annual temperature in the order of 75 ° C. Typical mean service temperature conditions are:
• Control cables ( multicore and multipair)
Srnm
FIG. 6.12 Details of dumb-bell samples
160 ° C to ensure the degradation mechanism is still representative of that occurring at the service temperature. For some high temperature materials it may be necessary to exceed 160 ° C to give acceptable testing ti mes, but even then a typical test programme can last up to 2 years. Samples of materials are removed from the ovens until the time is determined at which the
material exhibits 50 070 absolute elongation at break. A typical graph of such results is shown in Fig 6.13. From the four test results, a graph of reciprocal temperature against logarithm of time is plotted as shown in Fig 6.14. The Arrhenius activation energy is determined from the slope E a /kB of this graph using the method of least squares. For polymeric cable materials the activation energies are normally in the range of 0.85 and 1.65 eV. Having established the cable service conditions and material activation energies formula, Equation 6.2) can be used to calculate accelerated ageing time : for test purposes. Typical ageing times for various -:mperatures and activation energies are shown in Tables 6.3 and 6.4. From this information, the ageing time and temperature appropriate to the essential cable material having the lowest activation energy can be selected. Actual cable samples are then subjected to this ageing regime after which they are subjected to electrical and mechanical tests to ensure they are still serviceable.
3.11 Mechanical performance The mechanical properties of cables must be such that they will withstand the rigours of being installed along routes which could consist of horizontal and vertical ladder racks, through ducts and conduits, or direct in the ground. After installation cables must withstand the environmental conditions into which they are placed and these could include damp or oil contaminated situations. Materials such as PVC and PE have been freely available since the 1950s and therefore the mechanical performance of cables constructed from such materials has been evaluated and proved satisfactory from long
Cable types
375
275
250
225
150 1 60 1 C 25
1
2
T r 1405C
153C
00
75
50
25
600
300
300
1200
1 500
1 800
2100
2400
2700
3000
TIME (HOURS)
FtG. 6.13 Graph of 'elongation at break' plotted against time
TABLE 6.3 Power cable (service life 40 years at 75 ° C) ageing times at various temperatures Acti% at ion energy, CV
1.00 120
Ageing temperature I 50 ° C
Ageing temperature 135 ° C
days
110 days
12.5 days
41 days
40
1,40
4
days
15 days
1.60
1.5 days
6 days
experience. When introducing new cables into cable construction it is important to evaluate their mechanical properties and the performance of PVC can form a useful benchmark for such tests. Quite clearly the performance of the oversheath is of major importance and therefore the majority of testing must be concerned with evaluating this item. A typical range of type tests to evaluate mechanical performance includes: • Abrasion on complete cable. • Sheath cut-through. • Crush on complete cable. • Ozone resistance of insulation and oversheath.
TABLE 6.4
Control cable (service life 40 years at 40° C) ageing times at various temperatures etil, ation energy, eV
• Water permeation on bedding and oversheath materials. • Long term water immersion test.
Ageing temperature 135 ° C
Ageing temperature 115 ° C
0.85
7.5 days
33 days
1.00
1
• Mineral oil resistance of oversheath. • Pulling lubricant resistance of oversheath.
day
11 days
1.20
3 days
1.40
1 day
• Tear resistance of oversheath. • Retraction of oversheath. • Hot set on insulation, bedding and oversheath if cross-linked. 445
Chapte
Cabling
I
test machine operating in its compressive mode t, drive a cutting edge (see Fig 6.15) through the Over sheath of a complete cable sample. The force required to achieve this is monitored and compared against the acceptance criteria. The test is carried out at both ambient temperature and the estimated sheath operating temperature. The crush test is similar to the cut. through test, but the cutting edge is replaced by two parallel flat steel blocks 50 mm wide. In this case all metallic components in the cable are monitored and the force required to produce an electrical short is recorded and compared with the acceptance criterion. This test is intended to simulate a cable being crushed by, say, being walked on. The sheath penetration test is designed to simulate a cable being pulled over a sharp edge such as a hexagonal bolt head. In this test a weighted spike is moved along the cable sheath as shown diagrammatically in Fig 6.16. The acceptance
o'
1 03
Am, Mint BEFORE START OF RADIUS
1 02 21
22
23
24
25
26
27
26
29
z1 0) VT
FIG. 6.14
Arrhenius plot CABLE UNDER TEST
• Tensile strength and elongation at break on insulation, bedding and oversheath.
FIG.
6.15 Cut-through test
• Sheath penetration. • Hot pressure and hot deformation. Cut-through, crush, water permeation and tensile strength tests should be carried out on both aged and non-aged samples, the remaining tests being carried out on nonaged samples only. Many of these tests are covered by British or International Standards such as BS2782, BS6469, IEC 229 and IEC 540, and therefore further details are not included in this volume. However, the cut-through, crush, water immersion, oversheath retraction and penetration tests are less common and further details of these are included. The cut-through test is designed to measure the capability of the oversheath to withstand being rested on a sharp edge such as that which might occur with a cable tray. This test is performed using a tensile 446
FIG. 6.16
Sheath penetration test
Power cable system design ,riterion is based upon a voltage test being applied cable sheath although the depth of sheath he tomet t ration is recorded or information purposes. • the oversheath has a considerable impact Pc Because fire performance, there is a temptation on the ca bl e the oversheath heavily with fire-retardant fillers. till detract from its mechanical performance and has been found to make materials more suscepble to moisture. It is therefore important to carry :iout tests to ensure that the oversheath provides ademe protection against corrosion of the aluminium o ,,anised steel wire armour. It is also considered or oal essential to specify a long term water immersion test. Such a test consists of immersing cable samples in ater for a period of six months during which the insulation resistance and capacitance of the sheath are monitored. At the end of the test period the cable ,heaths are subjected to a voltage withstand test. This is particularly important for single-core cables %‘hich may be operated with armouring and, where applicable, screens bonded to earth at one end of the route only. Suitable test voltages are considered to be WO V AC for single - core cable sheaths and 500 V AC for the sheaths of all other cable types, the voltages being applied for I minute. After the voltage tests the samples are removed from the water and are dissected for a visual examination for water ingress or corrosion. Another test which experience has shown to be \ aluable is one to assess retraction of the oversheath. This is necessary to ensure that cable oversheaths do not pull out of the gland seals after the installation clue to thermal cycling. This test is therefore only necessary for power cables. The test procedure requires that a cable sample 10 m long be glanded at each end using mechanical glands of the type described in Section 9.1 of this chapter. The cable sample is laid straight and the position of the sheath entry into both glands is marked. The cable is then subjected to 40 load cycles between ambient temperature and its ma \imum continuous conductor temperature. After completion of the load cycles, the movement between the oversheath and the body of the gland, as indicated by the reference marks, is measured at both ends. A suitable acceptance criteria is considered to be that the measured values should not exceed 1 mm. 3.12 Electrical tests Electrical tests can be split into three categories, name-
• Bend tests; ambient and cold. • Voltage withstand; insulation and sheath. • Power factor measurement. • Load cycle (6350/11 000 V and above). • Partial discharge (6350/11 000 V and above). • I mpulse test. • Thermal ageing followed by voltage withstand, impulse and partial discharge as appropriate. 4 Power cable system design 4.1 Introduction As earlier described, the CEGB has adopted a
rationalised range of power cable conductor sizes for use at each of the three system voltage levels, i.e., 415 V, 3.3 kV and 11 kV. For each feeder or motor circuit application, a suitable conductor size, i.e., crosssectional area in mm 2 , has to be selected from the applicable range. The conductor size chosen is the smallest conductor size which meets, as applicable, certain technical requirements. The process of applying these technical requirements to derive this conductor size is called power cable system design. The technical requirements are primarily concerned with ensuring that current and voltage limits are not exceeded. For current, these are the current carrying capacity or rating of a cable for continuous operation and the magnitude, together with duration, of the current during an overload and a fault. The requirements for voltage involve the voltage regulation in the cable during normal operation and, where applicable, under motor starting conditions. In fundamental terms, the technical requirements are based on the need for a cable to have a reasonable service life, the prevention of thermal damage during an overload or a fault, and safe operation as shown against each requirement in the following: • Current rating for contin- Reasonable service life uous operation (including current sharing for singlecore cables with more than one cable per phase) • Voltage regulation
Safe or functional operation
• Overload current
Reasonable service life and thermal damage
• Dimensions.
• Short-circuit fault (phase to phase)
Safe operation and thermal damage
• Electrical characteristics, i.e., conductor resistance, insulation resistance, capacitance, inductance.
• Earth fault
Safe operation and thermal damage
!!, type, routine and site. Details of such tests are contained in the relevant International, British, ESI or CEGB standards which are referenced in Sections
3. ‘ 1 to 3.8 of this chapter. Therefore only a summary at types of tests that may be employed is given below:
447
Cabling
Chapter 6
• Sheath voltage (single-core cables)
Safe operation
• Maximum cable route length (certain types of 415 V circuits)
Safe operation and thermal damage
• Fault levels. • Protection relay operating times. • Voltage regulation limits. • Cable route lengths. • Types and details of cable routes.
Section 4.2 deals w ith the current rating of cables for continuous operation which, for single-core cables, includes the sheath armour voltage with single point bonding and current sharing with more than one cable per phase. Section 4.3 covers the three types of abnormal condition. These are short-circuit fault, earth fault and overload current, and considers their magnitude and duration relative to cable size for the prevention of thermal damage. Section 4.4 is a review of motor starting requirements and the determination of motor starting currents and times for different motor sizes. Section 4.5 deals with the calculation of voltage regulation, i.e., the percentage voltage drop in a supply system due to the impedance of the cables under both steady state and motor starting conditions. The appropriate cable sizes are determined for the voltage regulation limits within which the electrical plant and equipment is specified to operate. Section 4.6 examines the overall process of power cable system design as applied to feeder and motor circuits. This describes how the various technical
requirements are applied at each system voltage level and includes additional requirements specific to certain types of 415 V circuit. In the final part, the step-by-step procedure followed in selecting a cable size is demonstrated in a number of worked examples. In practice, the determination of each cable size by calculation is a repetitive and time consuming process. Consequently, tables have been developed for this purpose which enable the correct size to be quickly determined. In the case of continuous current ratings, these allow adjustments to be made for variations in the installation conditions. Some tables, but not all as they are too numerous, are included in the appendices to this chapter. It is necessary to have available certain design information before the task of power cable system design can commence. This, in turn, calls for the design of the power station electrical auxiliary system and plant layout/nfajor cable routes to be reasonably well advanced. To gain an initial appreciation of what this means, the extent of the design information needed is as follows: • Types of fault current breaking device and current rating. • Design load currents for feeder circuits. • Motor sizes and starting time for large motors. 448
• Ambient temperatures for cables laid in air. • Soil conditions for buried cables. • Installation configurations for single-core cables with more than one cable per phase.
In practice, difficulty is usually experienced in obtaining all of this information when cable sizing has to start and therefore assumptions may have to be made in order that the task can proceed. 4.2 Current rating for continuous operation The maximum or permissible current for continuous (or sustained) AC operation is determined, for a given cable conductor size, by the design of the cable and the conditions under which it is installed. The principal factors concerned may be summarised as: Design of cable • Conductor material. • Maximum conductor temperature for insulation. • Operating voltage. • Number of load-carrying conductors. • Cable overall construction. , Conditions under which installed • Ambient temperature. • Type of cable route. • Method of installation. • Method of armour bonding. The way each of these factors is taken into account can best be described by showing how the permissible current rating of a cable is calculated for the three types of cable route normally employed, i.e., cables laid in air, buried direct in the ground or laid in ducts. As will be seen, this process is solely concerned with ensuring that the temperature of the insulation does not exceed a maximum limit. Each of the above factors is involved with either the determination of the total heat produced within the cable, or affects the way this heat is lost to the surroundings. The current which balances these two during continuous operation at the maximum temperature limit is the permissible current
Power cable system design rating of the cable. The following describes in more detail how this current rating is derived.
The time taken to reach peak temperature is much shorter for cables laid in air than buried direct in the ground. Typically, for a large size cable, this is 2 4 hours when laid in air and in excess of 24 hours when buried direct in the ground. In Fig 6.18, the equilibrium temperature is just below the cable upper temperature limit, termed the maximum conductor temperature, for continuous operation. The value of this limit is normally determined by the choice of insulation and is derived from consideration of the electrical and mechanical properties of the insulation at the maximum conductor temperature. In particular, these properties must be retained without significant deterioration for a reasonable service life. Softening, leading to thinning of the insulation, during a thermal overload can also be a limiting factor with thermoplastic materials. By international agreement, standard maximum conductor temperatures have -
Maximum conductor temperature 4.2.1 heat is produced in a cable as the result of electrical lo“es due to the flow of current in the metallic components, i.e., conductors, screens and armours, and the presence of voltage. i.e., dielectric losses in the insuIdtion. The hottest part of the cable is the conductor and heat flows outwards to the cable surface to be Liissipated to the surrounding medium by conduction, nvection and radiation as shown in Fig 6.17, co If the cable current is steady, the cable temperature ambient until thermal equilibrium is reached riNes above ,,dien the rate at which heat is produced is equal to the rate at which it is lost to the surroundings, as hown for the conductor temperature in Fig 6.18,
CONDUCTOR INSULATION BEDDING /1 ARMOUR I I
1
I
OVERSnEATH
1
I
/1 1
SURROUNDING MEDIUM
TEMP
AMBIENT TEMP
RADIAL HEAT FLOW IS REASONABLY UNIFORM WITHIN THE CABLE BUT is NOT SO EXTERNALLY
DISTANCE FROM CABLE CENTRE
FIG.
6.17 Heat flow in cable
MAX CONDUCTOR TEMP
been assigned to all commonly-used insulation types and grades. Examples of these are shown in Table 6.5.
PEAK TEMPERATURE
TABLE
6.5
Maximum conductor temperature CONDUCTOR TEMP RISE
Insulation AMBIENT TEMP CABLE ENERGISED
Maximum conductor temperature, ° C
Polyvinyl chloride (PVC)
70
Butyl rubber
85
Ethylene propylene rubber (EPR)
90
Cross-linked polyethylene (XLPE)
90
TIME
FiG. 6.18 Conductor temperature rise 449
Cabling
Chapter 6
4.2.2 Ambient temperature
The conductor equilibrium temperature is equal to the sum of the ambient temperature plus the temperature rise. It therefore follows that before the temperature rise (i.e., current rating) can be determined, the ambient temperature must be known. The ambient temperature depends on the cable env ironment, which for cables laid in air is the surrounding air temperature and for cables buried direct in the ground is the soil temperature. Outdoors, the air temperature varies with geographical location, season, ti me of day, etc., which in turn influences the soil temperature. Inside a power station, the air temperature is closely controlled in certain rooms, but elsewhere varies with location from being approximately external air temperature in unheated areas to 50 ° C in parts of a boiler house or nuclear reactor building. In deciding the value to be adopted, it is not the mean but the highest ambient temperatures that need to be considered if the maximum conductor temperature is not to be exceeded. On this basis, values are selected for each cable environment. For outdoor environments, recommended temperatures are available and these are normally utilised. Typical values for cable ambient temperatures are shown in Table 6.6.
and maximum conductor temperature. Account is taken of the heat input from each electrical loss, relative to its position within the cable, and the heat flow through each non-metallic component to the surrounding medium. This treatment is described in IEC287 [II and for AC operation is obtained from the following formula: (I 2 R 2
+ [1 R (i +
where
Buried in ground
15
Laid in ducts
15
Outside in air
25
Inside in air
4.2.3 Conductor temperature rise
The steady state conductor temperature rise may be calculated mathematically, enabling the permissible current rating to be determined for a known ambient 450
+ X2) + Wd] n (T3 +
1
4)
current flowing in one conductor, A
Wd = dielectric loss per unit length for the
insulation surrounding the conductor, W/m Ti
thermal resistance per unit length between one conductor and the sheath, K.m/W
T2
= thermal resistance per unit length of the bedding between sheath and armour, K.m/W
13
thermal resistance per unit length of the external serving of the cable, K.m/W
14 = thermal resistance per unit length be-
tween the cable surface and the surrounding medium, K.m/W = number of load-carrying conductors in the cable (conductors of equal size and carrying the same load)
25-50
If for a cable laid in air the ambient temperature varies over different portions of the cable route, then clearly the highest ambient temperature involved must be used for cable sizing. With the large number of cables required for a power station, many of which will have parts of their route length at different ambient temperatures, the process of determining the correct ambient temperature for each cable becomes impractical. Therefore a high ambient temperature is adopted which covers all the cables within the power station, except for a few cables in extreme ambient temperature areas such as close to a boiler. These latter cables are easily dealt with separately.
+ Xi) + Wchn I T- 2
R = alternating current resistance per unit length of the conductor at maximum operating temperature, f2/m
Cable ambient temperatures
Ambient temperature, ° C
XL
[1 2 R (1
= conductor temperature rise above the ambient temperature, K =
TABLE 6.6
Environment
Wd)Ti
X
= ratio of losses in the metal sheath to total losses in all conductors in that cable
X2 =
Note:
ratio of losses in the armouring to total losses in all conductors in that cable
The expression is written in general terms. When applied to polymeric insulated cables, sheath becomes metallic screen (for 11 kV cables in power stations) and external serving becomes oversheath. The current rating for a four-core low voltage cable may be taken to be equal to the current rating of a three-core cable for the same voltage rating, conductor size and construction when used in a three-phase system with the fourth conductor as neutral. The dielectric losses (Wd) may be neglected for cables where the voltage between conductors and earth is less than 15 kV for EPR, 37 kV for XLPE and 6 kV for PVC, which is the case for the cables used
Power cable system design re arranging to i n power stations. Simplifying and obtain permissible current rating gives: -
AO RT1
nk ( 1 -"
) i2
nR (1 +
4-
”1„.3
14)
)
2
i s appropriate only to describe briefly the method of calculating each equation component. For further [nformation reference should be made to IEC 287. it
Conductor resistance (R)
Conductor resistance for AC operation includes an allowance for current distortion due to skin and proximity effects. Skin effect is the difference in current density between the centre of the conductor and the conductor surface due to the conductor AC magnetic field. Proximity effect is the difference in current dendue to the interaction of adjacent conductor(s) si ty and screen/armour AC magnetic fields. The AC resistance at maximum operating temperature is given by:
R = R (1 + where R
Yp)
= AC resistance of conductor at maximum operating temperature, 12/m
R'
DC resistance of conductor at maximum operating temperature, fl/m
Ys
the skin effect factor
Yp
the proximity effect factor
Both the skin and proximity effect factors are small for conductor sizes below about 150 mm 2 .
The DC resistance at maximum operating temperature is given by: R' = R [1 + a 20 (0 —
20
)1
where Ro = DC resistance of the conductor at 20 ° C,
12/m a zo = constant mass temperature coefficient at 20 ° C per kelvin (copper = 0.00393, aluminium = 0.00403) 0
maximum operating temperature,
°
C (determined by the type of insulation)
Appendices A and B list values of AC and DC resistance for single - core and multicore power station cables respectively.
currents. Circulating currents occur with solid bonded cables, i.e., armour bonded to earth at both ends, the flow around the armour/earth return loop being induced by the transformer action between the conductor and the screen/armour (the screen is bonded to the armour at both ends). Eddy currents are the result of dissymmetry in the magnetic field caused by manufacturing limitations and the installation arrangement. The use of non-ferrous metals, i.e., aluminium instead of steel wire armour, reduces these losses. Circulating currents in the armour of single-core cables can be equal to an appreciable proportion of the conductor current, the magnitude being dependent on the load current and the method of installation. These circulating currents reduce the rating of these cables. For example, with 11 kV single-core cables installed in air in flat formation, as described in Section 4.2.5 of this chapter, the reduction caused by circulating currents is approximately 11 070 for a 300 mm 2 and 17% for a 500 mm 2 size cable. This reduction may be avoided by single-point bonding, i.e., bonding the armour to earth at one end only, which prevents current circulating. This, however, induces a standing voltage in the cable armour which is at a maximum at the unearthed end of the cable armour. With multicore cables, two-core phase and neutral, and three and four core cables carrying a three-phase current, the losses are small and have little affect on rating and are normally only taken into account for steel wire armoured cables. Multicore cables may therefore he bonded to earth at both ends without any penalty to their rating. Thermal resistances of cable components (Ti T3)
T2
and
To calculate the thermal resistance of the insulation (Ti), bedding (T2) and oversheath (T3) the thermal resistivity of each component must be known. Thermal resistivity is defined as the difference in temperature (in kelvin), between opposite faces of a metre cube of material caused by the transference of one watt of heat. In other words, the lower the value of thermal resistivity the better the material is at transferring heat. The thermal resistivity values for a number of materials are given in IEC 287, the most commonly used are shown in Table 6.7. Using an 11 kV single-core cable as an example, the thermal resistance (Ti) between conductor and metallic screen is given by: T 1 = (Q 1 /27r) x log n (1 + 2t /d e ) where Qi = thermal resistivity of insulation, K.m/W
Metallic screen and armour loss ratios (X and X2)
d c = diameter of conductor, mm
Cable metallic screen and armour losses are produced by circulating currents and to a much less extent eddy
t
= thickness of insulation between conductor and metallic screen, mm 451
IP" Cabling
Chapter 6 The thermal resistance T4 is given by:
TABLE 6.7 Values of thermal resistivity for cable materials
Material
1
T4 —
Thermal resistivity, K.m/W
Deh(&00 7
Insulation
PVC up to 3 kV
5.0
abo%e 3 kV
6.0
EPR up to 3 kV above 3 kV XLPE Butyl rubber
h—
3.5 5.0 1.5
where D e = external diameter of cable, m
5,0
h
= heat dissipation coefficient, W/m2 (K)E 25
Sheathing
PVC up to 15 kV
5.0
AOs =
Semi-conducting layers are considered part of the insulation. The thermal resistance (T2) between metallic screen and armour is given by: T2 =(QT/27) X log n (1 + 2t2/D 5
where
QT
t2
)
thermal resistivity of bedding, K.m/W = thickness of bedding, mm
D s = external diameter of metallic screen, mm
=(@T/27r)
Cables buried direct in the ground The thermal resistance for a single isolated buried cable is given by: T4 = (Q T /2r)
QT
thermal resistivity of oversheath, K.m/W
C3
thickness of oversheath, mm
D'a
external diameter of the armour, mm
To calculate the thermal resistance of the insulation for multicore cables reference should be made to IEC 287. External thermal resistance (Ed Cables laid in free air (protected from solar radiation) Heat dissipation from an isolated cable laid in free air is mainly by convection, but a proportion will be emitted by radiation to be absorbed by the enveloping surface or transmitted by conduction to the cable support system. In this respect, cables with larger diameters dissipate heat better than smaller cables because of the increased surface area. The close proximity of other cables or a vertical wall reduces heat dissipation. For example, with three single-core cables the heat dissipation and hence current rating is lowest when they are installed in trefoil. The heat dissipation and current rating is improved when the cables are placed in a flat spaced vertical formation and the highest rating is achieved with a flat spaced horizontal formation. 452
x log,
-■/(u 2 — I)]
x log, (1 + 2t3/D)
where where
excess of cable surface temperature above ambient temperature, K
The heat dissipation factor constants Z, E and g for one, two or three cables either installed spaced or touching, supported away from or cleated direct to a vertical wall, are detailed in IEC 287. Cables installed outdoors in air are normally shielded from the sun, but if directly exposed, separate calculations must be performed which take account of the heating due to solar radiation.
The thermal resistance (13) of the oversheath is given by: T3
E ( D e )g
QT =
the thermal resistivity of the soil, K.m/W
= 2L/D, L = distance from the surface of the ground to the cable axis, mm D e = external diameter of cable, mm The thermal resistivity of the soil depends on the backfill material, degree of compaction, make-up of the original ground and moisture content. Thorough compaction of the backfill material is essential to obtain a satisfactory resistivity. Of the remaining factors, the most important is moisture content which varies the soil thermal resistivity to such an extent that, for most purposes, the effect of soil type can be ignored. This variation is shown in Table 6.8. At depths of 0.8 m and less, the soil moisture content is dependent on the prevailing weather which varies with geographical location, time of year, etc. Soil thermal resistivity is difficult to measure and for most applications it is convenient to use a standard value representative of the all year round maximum soil thermal resistivity. This condition in average soil (i.e., clay or loam) is when the soil is damp but not quite moist, corresponding to a value of 1.2 K.m/W.
Power cable system design TABLE 6.8 Vat-lotion of thermal resistivity with soil moisture content
Thermal esiin ity,
1) 7
0 2.0 3.0
Sod i:ondition
Weather condition
Very moist
Continuously moist
Moist
Regular rainfall
Dry
Seldom rains
Very dry
Little or no rain
In selecting this value it is assumed that drying out does not occur when the cable is carrying at the soil
full-load current. This may not be the case in well or loosely compacted soil, etc., for example, Jrained cand or made-up ground, and in these circumstances a higher value must be used.
In this instance the external resistance consists of three parts, namely: ihermal Cables laid in ducts
• The thermal resistance of the air space between the cable surface and the duet internal surface T4. • The thermal resistance of the duct T. • The external thermal resistance of the duct TZ.
Equations are available in IEC 287 for the calculation 01 each thermal resistance. The value of T4 is given b!, he sum of the individual thermal resistances, i.e.,
Values of thermal resistivity for the two duct materials (taken from IEC 287) are given in Table 6.9.
ki , ed
TABLE 6.9 Values of thermal resistivity for duct installation
N,laterial
Thermal resistivity, K.m/W
Concrete*
1.0
Earthenware
1.2
• Typical, as value varies with mix.
4.2.4 Permissible current ratings
has already been done and the values are readily available from a number of sources, notably ERA Technology. The same applies for cables manufactured to
CEGB Standards except that the values are not as widely available. The CEGB has its own computer program for this purpose which is used for instances where published data is not available. The source of the current ratings for power station cables are as follows: • 11 kV single core power cables (GDCD 17 [2,])
CEGB calculated (90 ° C maximum conductor temperature).
• 415 V and 3.3 kV single-core cables
CEGB calculated (90 ° C maximum conductor temperature).
• 415 V and 3.3 kV multicore cables (BS6346 [3])
-
ERA Report 69-30 Part III [4] (70 ° C maximum conductor temperature).
The current ratings for these cables are tabulated in Appendices C and D of this chapter for the three types of cable route described. As it is impractical to tabulate these for every possible variation under which the cables may be installed, these are presented for the set of standard installation conditions defined in the next . section. Rating factors are then given to enable the current rating to be corrected for any variation from these conditions. For convenience, the AC current ratings for two-core cables are also applied for DC operation. If a circuit involves more than one type of cable route, e.g., a portion is laid in air and a portion buried direct in the ground, then the lowest of the current rating values (after application of any rating factors) must be used for the current rating of the cable. This is an important point when designing an external cable route as the decision on which type of cable route to use can make a difference to the size and hence cost of the cables required. For example, it can be seen from examination of the tables in Appendix D that for the larger sizes of multicore power cable the current rating is significantly reduced if laid in ducts, whereas if buried direct in the ground the current ratings are higher than in air for all except the largest cable size. With single-core power cables the reduction is of the same order, whether the cables are laid in ducts or buried direct in the ground. Short lengths of duct (normally less than half a metre) are ignored for cable sizing purposes. The longitudinal conduction of heat by the cable metallic components is considered sufficient to maintain a uniform temperature rise.
Tubulated ratings
In practice,
there is no need to perform the calculations described to determine the current ratings for ,. ahles manufactured to British Standards. This work
Standard installation condition
The standard installation conditions for the tabulated current ratings are: 453
Cabling
Chapter 6 •
(a) Method of armour bonding: •
Single-core power cables — single end bonded to earth.
•
Multicore power cables
— solid bonded for all circuits except final 415 V feeder circuits which are single-end bonded to earth (see Section 4.6.1 of this chapter).
(b) Cables laid in air: •
Supporting structure
•
Ambient temperature
•
Method of installation
horizontal and vertical ladder rack and tray spaced from walls by at least one third of cable diameter. — 25 ° C.
for single core power cables
— single-layer flat spaced at 80 mm centres
for multicore power cables 35 mm 2 and above
— single-layer flat spaced 25 mm apart.
for multicore power cables 16 mm 2 and less
— random mix doublelayer touching.
(c) Cables buried direct in the ground: •
Depth of laying (measured from the ground surface to the centre of the cable) single-core power cables — 0.8 m. 3.3 kV multicore cables — 0.8 m. 415 V multicore cables — 0.5 m.
•
Ground temperature
— 15 ° C.
•
Soil thermal resistivity
— 1.2 K.m/W.
•
Method of installation for single-core power cables
— single-layer flat spaced one cable diameter apart.
for multicore power cables 35 mm 2 and above
single-layer flat spaced one cable diameter apart.
for multicore power cables 16 mm 2 and less
random mix doublelayer touching.
(d) Cables laid in ducts: •
454
Type of duct internal diameter material
— 100 mm. — earthenware.
Depth of duct (measured from the ground surface to the centre of the cable). single-core power cables — 0.8 m. 3.3 kV multicore power cables — 0.8 m. 415 V multicore power cables 0.5 m. 15 ° C.
•
Ground temperature
•
Duct thermal resistivity — 1.2 K.m/W,
•
Method of installation for single-core power cables for multicore power cables 35 mm 2 and above for multicore power cables 16 mm 2 and less
— three ducts in flat formation. single duct.
— random mix touching.
4.2.5 Rating factors
With conditions other than the standard installation conditions described, it is necessary to adjust the tabulated current rating to correct for the difference. This may be for a variation in the thermal parameters of the surrounding medium, i.e., ambient temperature, depth of burial or soil thermal resistivity, or because the cable is grouped with others. The correction is performed by multiplying the tabulated current rating by a rating factor. The rating factor to be applied is obtained from tables produced for this purpose which cover the normal variations in installation conditions. Where there is more than one variation to the standard installation conditions then the rating factor for each must be multiplied together to obtain the overall factor. Care is however required to ensure that only the relevant factors are applied to each section. For instance, if a portion of a cable route is in air and a portion buried in the ground, the rating factor for a different ambient air temperature is only applied to the laid in air current rating and that for a different depth of laying is only applied to the buried in the ground current rating, and not, as sometimes mistakenly happens, both applied throughout.
Rating factors for variations in thermal parameters Tabulated rating factors are available for the following variations in the thermal parameters of the surroundings: ° • Variation in ambient temperature (90 ° C and 70 C maximum conductor temperature). ° • Variation in ground temperature (90 ° C and 70 C maximum conductor temperature) for cables laid direct in the ground. ° • Variation in ground temperature (90 ° C and 70 C maximum conductor temperature) for cables laid in ducts-:
Power cable system design Variation in depth of laying cables direct in the
•
gr ound.
Variation in soil thermal resistivity for cables laid •
wse rating factors are given in Appendix E of this
I D RATING FACTOR
direct in the ground. ,n soil thermal resistivity for cables laid • variation in ducts. variation in depth of laying ducts. •
4151/ CAFILES LAID HORIZONTALLY IN AIR
09
1.1 ■
11,1 pter.
Group rating factors
l 0
lt has earlier been mentioned that the current rating for an isolated multicore cable or set of three singlecore cables needs to be reduced if installed in close pro \imity to neighbouring cables. This is due to mutual heating and applies irrespective of the type of cable route. For cables laid in air the effect of being close to also has to be included. A reduction is avoided a %%all if cables are installed above certain minimum spacings ,thich, typically for cables laid in air, are shown in 6.19. Unless the current rating is calculated for the method of installation concerned, it follows that group rating
1 5
2 0
AXIAL SPACING A Ele)
FIG. 6.20 Rating factors for three spaced cables
such an arrangement. As is shown in the following, the method of cable installation adopted derives benefit from avoiding any reduction due to group rating while at the same time efficiently utilises cable support steelwork space.
Hg
must be applied to the isolated current ratings for multicore cables or groups of three single-core cables 1k
hen spaced apart by less than the minimum distance
415 V. 3,3 kV and 11 kV single-core power cables
The method of installation is flat spaced in a singlelayer at 80 mm centres as shown in Fig 6.21. Ratings are calculated using this spacing.
necessary to achieve the isolated condition. This includes single - layer and multi - layer touching cables. The
typical rating factors for three spaced cables taken from ERA 69-30 Part III are shown in Fig 6.20. Since the vast majority of power station cables are laid in air it is highly desirable that adequate space is provided between these cables to allow the isolated current rating to be used. However this need has to be balanced against the cost of providing the additional room and cable supporting steelwork to accommodate
6.2I Method of installing single-core cables 551 5 De
415 V and 3.3 kV multicore power cables (35 mm 2
and above) are installed flat in a single - layer spaced apart by 25 mm as shown in Fig 6.22.
O/ CF l'Yi0 CABLES
5)2 Oe
CW OF -D-rFEE CABLES
Fic,. 6.19 Minimum cable spacings
Flo. 6.22 Method of installing multicore power cables (35 mm 2 and above) 455
Cabling
Chapter 6 M
mMIN
Where the two cables are of a different size, spacings are based on the larger of the two cable diameters to err on the safe side. On the same basis, if each cable size considered from the range of multicore cables is the cable with the highest number of cores, i.e., has the largest cable diameter, then all cables of this size with fewer cores are covered by this cable. Table 6.10 shows the axial spacings between these cables, using the cable design maximum overall diameters and the group rating factor. The lowest value of group rating Factor is 0.98 for the 3.3 kV 3-core 240 mm 2 and 415 V 4-core 300 mm 2 cables. Besides being almost negligible, if the argument on loading ratio made in the next section is applied, it is apparent that there is no need to apply group rating factors to these cables.
complex with heat also travelling outwards across adjacent cables and air pockets to reach the exterior surface of the cable group. To determine the group rating factor, it is assumed that there is uniform heat generation throughout the cross-section of the cable group, from which it follows that the acceptable power loss from each cable is pro. portional to its cross-sectional area. Since the heat generation is uniform this also means that a cable can be located at any position within the group. On this basis, the group rating factor may be calculated if the heat dissipation coefficient and thermal resistivity of the group is known, i.e., the cable group is treated as behaving like a single cable. These parameters have been determined experimentally by the CEGB for a
TABLE 6.10
Approximate axial space between multicore power cable centres and group rating factor Maximum overall diameter D e , mm
Approx. axial spacing between cable centres
Group rating factor
3.3 kV 3-core 150 mm 2
47.9
1.5 D e
0.99
2
55.7
1.4 D e
0.98
4-core 35 mm 2
1.0
Cable voltage/size
3-core 240 mm 415 V
26.2
2.0 D e
2
34.0
1.7 D e
1.0
4-core 120 mm 2
42.7
1.6 D e
0.99
4-core 185 mm 2
52.1
1.5 D e
0.99
4-core 300 mm 2
64.0
1.4 D e
0.98
4-core 70 mm
(16 mm 2 and less) are random laid double-layer touching as shown in Fig 6.23. 415 V multicore power cables
RANDOM FILL DOUBLE LAY5R TOUCHING
double-layer group of cables, thus enabling the group rating factor for each cable size to be found. At this point it is necessary to introduce the term loading ratio which is defined as the ratio of normal full-load current to permissible current rating after applying any rating factor for variations in the thermal parameters. If a group rating factor is now applied to the permissible current rating, it follows that: LR = IFL/Ip and OR
FIG. 6.23 Method of installing multicore power cables (16 mm 2 and less)
Cables are rarely laid straight and parallel and may be laid loose enough to allow some air to pass through, but this cannot be used as a basis for calculating current ratings and the worst case must be assumed which is when the cables are tightly packed. In this situation, air flow between the cables is practically non-existent and heat dissipation is now more 456
where LR = loading ratio [FL = full load current I p = permissible cable current after applying any rating factors for variations in thermal parameters GR = group rating factor IG = permissible current rating after applying a group rating factor From the two equations it can be seen that provided LR OR there is no need to take account of the cable group rating factor.
Power cable system design The CEGB has also carefully examined the range 2 f loading ratios for cables sizes 16 mm and less o for feeder and motor circuits. As seen in the practical rnples later, these cables are mainly sized to meet e ,(a itage regulation requirements and as a result are w often larger than required for continuous full-load current operation, By comparing the loading ratio with he group rating factor, it was found in all cases exmined that the former was less for motor circuits and a lso for most feeder circuits. Since cables are installed a in what in all probability will be a mixture of circuit t%pes, and not all will be in service at the same time, judgement has been made that there is no need to 3 pply group rating factors to these cables. This policy a has been followed for some years and service experience to date has supported this decision.
To obtain optimum current-sharing, each cable of any phase must 'see' the same magnetic field as the others in that phase and this is achieved by using a symmetrical arrangement such as that shown in Fig 6.25.
Cables buried direct or in ducts
The same considerations as those just discussed can be applied to cables buried direct in the ground except that here the minimum spacings necessary to avoid a reduction in the current rating due to mutual heating are much greater. The net result is that group rating factors are applied where necessary. These are available from ERA 69-30 Part III for cables buried in flat formation with various axial spacings from touching to 0,6 m between cable centres for different numbers of cables in the group. This situation is repeated for cables laid in ducts. Group rating factors are available for different spacings/formations of cable ducts for multicore and three single-core power cables.
FiG. 6.25 Cable installation with two and four cables per phase
This formation may be repeated for four cables per phase, by arranging the cable rows in tiers on separate steelwork levels as shown in the figure. Unfortunately this arrangement does not work with larger even numbers or odd numbers of cables per phase and the only way to achieve symmetry is by cable transposition. Transposition involves the interchange of cable positions so that each cable occupies the same space relative to the others for approximately onethird of the cable route length, as shown in Fig 6.26.
4.2.6 Single-core cables in parallel
Current sharing
Feeder circuits are frequently required to transfer high levels of power with currents up to 3000 A. Single core cables are used for this purpose and from examination of the ratings for single-core cables, it can be seen that 1:1..eral cables in parallel per phase are needed. With this arrangement, it is necessary to ensure that he current is shared approximately equally between each cable in parallel and that individual cables are not overloaded by exceeding their permissible current rating. This is particularly important for cables laid )paced in flat formation where lack of symmetry, as )hown in Fig 6.24 for two cables per phase, results in unequal current sharing. -
Fig. 6.24 Lack of cable symmetry
I
-
TOTAL LENGTH OF CABLE I
FIG.
6,26 Cable transposition
The CEGB has developed a computer program CURB03 [5] to calculate the current sharing between cables in parallel. To determine the current in each cable, the cable axial co-ordinates and length for each route section are entered into the computer program, together with the number of cables per phase, phase current, cable conductor resistance, armour details, etc. The output from the computer contains the current in 457
PPP-
Cabling
Chapter 6 .01=1•••
each cable which is checked against the cable permissible current rating as described earlier. The computer also calculates the voltage drop in the cables.
For most power cables ri = r2 =r, from which it can be shown that: [2r
- rf)] log, (r2/ri) =
Sheath voltage
As mentioned in Section 4.2.3 of this chapter, the bonding of single-core power cables at one end only produces a standing voltage on the metallic screen/ armour. This voltage appears across the cable sheathing (hence is usually called the sheath voltage); its magnitude is proportional to the conductor current and cable route length, the maximum value appearing at the cable screen/armour insulated (open) end. At full load current, the standing voltage on the screen/ armour which is connected to the cable gland must not exceed the maximum allowable touch voltage of 55 V (see Section 11.2.2 of this chapter). In the event of a through fault, the induced voltage will reach a much higher value for the short duration of the fault. The cable oversheath and the gland insulation are designed to withstand this voltage up to a limit of 2 kV. To protect personnel from this condition, the accessible metal body of the cable gland is covered with a PVC shroud. It is necessary to calculate the sheath voltage for these two conditions to ensure that the maximum voltages do not exceed the above limits. The two sheath voltage conditions described above are illustrated in Fig 6.27.
Hence Vs = 47rfI 10
-7
log, (sir) V/m
The standing sheath voltage for the outer cables is given by:
Vs = j2.7rfI 10 11 - [2r /(ri - ri)] log, (r2/r 1 ) 1og 0 2) V/m + 2 log, ('12s/r2) ± again if r1 = r2 = r Vs = j2irfl 10 -7 [2 log e (V2s/r) ± j -s/3 log e ] V/m then in magnitude Vs1 = 27rfI 10 -7 ([2 log, (N/2 s/r)] 2 + (V3 log, 2) 2 ) 2 Virn
27rfl 10 -7 42 Log i, (- 12 s/r)I 2 + 1.44) 2 Vial The standing sheath voltages with transposed cables are all equal and are given by: V s = 27rfl 10 - 7 (1
[2r/(r i - ri)1 log (r2/ri) + 2 log n (3 s/2s/r2)) V/m -
-
again if r1 = r2 = r Vs = 47rfl 10 -7 log, (3./2s/r2) V/m
SINGLE CORE POWER CABLE
GLAND CONNECTION TO EARTH
STANDING VOLTAGE UNDER NORMAL OPERATION <555/ UP TO A MAXIMUM FOR A THROUGH FAULT <2kV
Fin. 6.27 Sheath voltage
For cables installed in flat formation without transposition, the standing sheath voltage on the centre cable differs from that on the two outer cables. The sheath voltage for the centre cable is given by: Vs -= 27rfI 10 -7 (1 - [2r/(1- 3 - r1)] log0(r2/rt) + 2 log 0 (s/r2)) V/m where f = frequency, Hz = full load current, A r = inner radius of cable armour, m r2 = outer radius of cable armour, m s = separation between centres of adjacent cables, in 458
The sheath voltage can also be calculated usir , he CEGB computer program CURB03. For practical purposes, the sheath voltage under short-circuit conditions can be taken as the full load current sheath voltage increased in proportion to the ratio of the short-circuit current to the full load current, as shown in the following expression: VSC = VFL
X
ISC/IFL
where Vsc = short-circuit sheath voltage VFL = standing sheath voltage Isc = short-circuit current 'FL = full load current Design values for short circuit current are given in Table 6.11. If the standing or short-circuit sheath voltage is found to exceed the maximum permitted, it becomes necessary to solid-bond the cable screen/armour at both ends and fit a sheath interrupter at the approximate mid-point of the cable route. A sheath interrupter is a device which allows the removal of a short length
Power cable system design TABLE 6.11 MaXiniuM
symmetrical short-circuit currents
Maximum symmetrical fault Fault leeI. MVA
Current, kA RMS
75 0
39.4
3.3 0 315
250
43,7
31
43.3
f the cable armour and metallic screen, and the subequent reinstatement of the cable sheath at that point. The sheath voltages are therefore approximately halved and transferred away from personnel touch to the cut ads of the armour and metallic screen within the sheath c interrupter. However, it is still necessary to calculate the sheath voltage under fault conditions and keep it Olin the 2 kV limit (the design withstand voltage of ■k the oversheath). These techniques are normally more than adequate for the cable route lengths found in porAer stations but if the 2 kV limit cannot be achieved using these techniques, then more difficult and expenive solutions such as cross-bonding have to be used. o
the main protection, the short-circuit fault clearance ti me is in the order of 0.1 s. However, as a precaution, it is normal cable sizing practice to assume a minimum main protection fault clearance time of 0.2 s. Although the probability is low, there remains the possibility that for some reason a circuit-breaker might fail to open. In this event, a fault would have to be cleared by the next circuit-breaker back in the supply line which is usually the switchboard incoming feeder circuit-breaker. The total fault clearance time for a short-circuit is now determined by the protection fitted to this circuit which is either high set instantaneous overcurrent or IDMT overcurrent. This is called the back-up protection fault clearance time and can vary from 0.4 s to 1.2 s. Due to the length of time required to replace a
damaged cable, it is CEGB policy for new power stations to size cables using the back-up protection fault clearance time on all circuits with a circuit-breaker as the fault current breaking device. A typical oscillogram for the current in one phase of a three-phase shortcircuit is shown in Fig 6.28. :uRRENT
INITALASYMMETRICAL CURRENT
FAuLT INCEPT'ON
pmssymmE „ cu,i2E,T
4.3 Fault current and duration The foregoing has described the process of determining the conductor size for a cable which will ensure that the maximum conductor temperature of the insulation is not exceeded during continuous operation. During a fault, however, abnormal currents can result in much higher temperatures which, unless the cable is adequately protected, could cause serious damage to the insulation or at worst start a cable fire. Insulation damage can occur over a period of several hours due to an overload, or within a fraction of a second due to a short-circuit or an earth fault. It is therefore equally important with power cable system design to ensure that the cable is adequately protected against all forms of excess current. This is achieved by coordinating the operating characteristics of the circuit protection with the fault current capability of the cable. 4.3.1 Short circuit -
faults
I1 is appropriate to commence with a review of the n short-circuit current (due to a three-phase shortircuit) used at each system voltage level, as shown in Fable 6.11, and the types of fault current breaking device and main protection used for feeder and motor ircuits, as shown in Appendix I. In this respect, feeder Nuits include interconnector and transformer circuits. The total clearance time for a fault cleared by a cIrcuit-breaker may be taken as the sum of the protection relay operating time and circuit-breaker opening ti me. With high set instantaneous overcurrent as c_ie
1 1 ,
1
, „
nmE
FAULT CLEARED
FIG. 6.28 Oscillogram of current in one phase of a
three-phase short-circuit
The same concern about failure to operate is not held about a fuse. Therefore, the total fault clearance time for fuse protected circuits is given by the maximum pre-arcing time, i.e., the energy let-through time determined from the fuse time versus current characteristic, of the circuit fuse. At 415 V, the largest size of fuse fitted is 800 A used on feeder circuits. Assuming maximum short-circuit current, the pre-arcing time with this fuse is about 0.01 s. This means that circuit interruption occurs during the first half cycle of the fault current. The sudden rush of current causes the conductor temperature to rise at an extreme race. Disconnection is followed by a period of fairly rapid cooling. The rise in conductor temperature is typically as shown in Fig 6.29, with the cable initially carrying rated current. The conductor is at the maximum conductor temperature and rises to a peak at the maximum short - circuit conductor temperature. If the cable had been initially 459
Cabling
Chapter 6
TEMP MAXIMUM SHORT CIRCUIT CONDUCTOR TEMP
SHORT CMCLIIT FAULT DURING NORMAL OPERA PON
by the adjacent cable components and the error this introduces provides a margin of safety. The temperature rise is calculated by equating the energy input to the energy absorbed expressed by the following formula: 2
1 2 t = K 2 S log n [(Of
YAMMUMCONDUCTORTEMP
where I K
AMBIENT TEMP
=
short-circuit current rms, A
=
duration of short-circuit, s
=
constant depending on the material of the current carrying component
=
area of conductor, mm 2
8f ei
final temperature, =
°
initial temperature,
C °
C
= reciprocal of temperature coefficient of resistance of current carrying component at 0 ° C
TIME
SHORT CMCUIT FAULT
+ O )/(O; + i3)]
FIG. 6.29 Short-circuit conductor temperature rise
Qc (0 + 20)]T
unloaded, the temperature rise from ambient would be as shown dotted. As the duration of the temperature rise is short, the cable insulation and other components can withstand considerably higher temperatures without suffering permanent damage. By international agreement, standard maximum short-circuit conductor temperatures have been assigned to the commonly used cable materials. Several of these are given in Table 6.12.
K —[
Q20
where Qc = volumetric specific heat of the current carrying component at 20 ° C, J/°C mm 3 e2o = resistivity of current carrying component at 20 ° C, f2 mm The constants for different conductor materials are given in Table 6.13.
TABLE 6.12 TABLE 6.13
Maximum short-circuit conductor temperature
Material constants for fault calculations
Material
Temperature,
°
C Material
K
QC
Q20
Insulation
PVC up to 300 mm 2 Butyl rubber EPR XL PE
160 220 250 250
17.241 x 10 -6
Copper
226
234.5
3.45 x I0
-
Aluminium
148
228
2.5
x 10
-3
28.264 x 10 -6
78
202
3.8
x 10 -3
138 x 10 -6
Steel
Sheathing
PVC
160
Two assumptions are made to assist with the calculation of the short-circuit temperature rise for circuitbreaker controlled circuits. The first is that all the heat energy produced is absorbed by the current carrying components, i.e., the temperature rise is adiabatic. The second is that over the duration of the short-circuit the current remains constant. The effects of the current initial asymmetry and slight fall-off in current due to the increase in circuit resistance with temperature can be regarded as negligible. In practice, a certain amount of heat is absorbed 460
It can be seen that since the temperature rise is adiabatic it is independent of the number of cable conductors. It should also be noted that when used for metallic screens, this formula indicates much higher temperatures than actually occur in practice and therefore must be used with some discretion. For cable sizing purposes it is convenient to assume that the cable is operating at the maximum conductor temperature when the short-circuit occurs, and that the peak temperature reached is the maximum short-circuit conductor temperature. For a given cable insulation/ type, this leaves the short-circuit current, duration and cable sizes as variables and these may be plotted graphically (as shown in Fig 6.30) with initial and final
Power cable system design of this chapter because in this case fuses are selected to match motor starting conditions not full-load current requirements.
• 20
0L0
4.3.2 Earth faults
41.PECPR
With earth faults, both the conductor and the metallic screen/armour (which provide a low impedance path for earth fault current to return to the system neutral) need to be considered. Clearly, the temperature reached by each fault current-carrying component must not cause thermal damage to the cable. The maximum short-circuit temperature of the insulation and bedding must not be exceeded with fault current in the metallic screen and similarly the maximum short-circuit tem-
.-100rnm'
NOTE BASED ON A 1E1.IPE., V4TU 6 E RISE OF •60°O
42
300mm ,
03
04
06
48 10
3_0 s
20
perature of the bedding and oversheath must not be exceeded with fault current in the armour. Using the same expression for the adiabatic temperature rise and the material constants given in Table 6.13, the minimum cross-sectional area for the metallic screen/ armour can be calculated. In this instance:
DURATION OF SHORT.CIRCUIT
FIG. 6.30 Short-circuit ratings of XLPE/EPR insulated
cables with aluminium conductors
° ° temperatures of 90 C and 250 C respectively, i.e., ° a 160 C temperature rise. Using the above assumptions and the maximum
I = earth fault current, A t = duration of earth fault, s S = area of metallic screen/armour, mm 2 I3f = final metallic screen/armour temperature, e t = initial temperature of the metallic screen/ armour, ° C
short circuit current, the minimum size cable required -
can also be calculated for a range of total fault clearance times. These are shown in Table 6.14 for singlecore power cables at each system voltage.
°
C
TABLE 6.14 Single-core power cable minimum cross-sectional areas
System voltage kV
Min CSA main protection mm 2
Min CSA back-up protection, mm 2
0.2 s
0.4 s
0.6 s
0.8 s
1.0 s
1.2 s
186
264
323
373
417
457
3.3
207
293
358
414
463
507
0.415
205
290
355
410
458
502
11
if it can be established that the cable will always be operating at a temperature less than
the maximum conductor temperature, then the minimum cross-sectional area may be calculated for the lower temperature concerned.. With circuits protected by fuses, the short circuit temperature is determined by the 1 2 1 'let-through energY' of the fuse. Fuse manufacturers provide 1 2 t values tor each fuse size from which the minimum cable crosswetional area can be calculated. This is not necessary With feeder circuits, as short-circuit requirements are automatically covered by the selection of a cable to match the fuse rating. However, this needs to be carried out for motor circuits as described in Section 4.6.2 -
The initial temperature for the metallic screen has to be calculated, but for the armour is taken as being 10 ° C below the maximum conductor temperature. The maximum temperature for the metallic screen/armour is normally the maximum short-circuit temperature for the sheathing material which, from Table 6.12, is 160 ° C. Cable armour cross-sectional areas are given in Appendix F of this chapter. To determine the earth fault current it is necessary first to examine the method of system neutral earthing which, for a power station, is shown in Table 6.15. At 3.3 kV and 11 kV the neutral earthing resistor limits the maximum earth fault current to 1000 A at each neutral: As two system supplies and hence two 461
IP" Cabling
Chapter 6 TABLE 6.15
greater than that of the conductor, and therefore ther e
System neutral earthing System voltage, kV
is no need to perform the calculation.
Neutral earthing
4.3.3 Overload current
NER (1000 A) 3.3
NER (1000 A)
0.415
Solid
NER — Neutral earthing resistor
neutrals can be involved, this gives a maximum fault current of 2000 A. Sensitive earth fault protection is provided for feeder and motor circuits. The total fault clearance time is again assumed to be 0.2 s for the main protection and typically twice this time for the back-up protection to operate. In practice, the crosssectional area of the metallic screen is rated at 1000 A for 1 s. It can also be shown that the minimum armour cross-sectional area required is well within the design of the cables. For example, the one second rating for a 3.3 kV 240 mm 2 multicore (aluminium strip armoured) cable is approximately 16.8 kA. At 415 V, the system neutral is solidly earthed and therefore the fault current is determined by the earth loop i mpedance as shown in Fig 6.31.
3 5 .V 4155 TRANSFORMER HV WINDING CMiTTED ,
ANSPOR M ER mPEDANCE
- T 5V SWITCHBOARD DISTRIBUTION I MPEDANCE
415V MOTOR CABLE I MPEDANCE
Cables must also be protected against thermal damag e due to an overload. This could occur due to the inadvertent connection of too large a load, but is mor e likely to be associated with a faulty item of plant such as a motor or transformer. The overload does not need to be a significant increase above the cable continuous current rating to have an effect, as even a modest overload results in a marked temperature rise. In particular, thermoplastic insulation is at greatest risk due to softening and conductor migration. The requirements for overload protection of a cable laid in air are taken from the IEE Wiring Regulation (15th Edition) Regulation 433-2 [9j, which states that the characteristic of a device protecting a circuit against overload shall satisfy the following conditions: • Its nominal current or current setting (II„) is riot less than the design current (Ib) of the circuit. • Its nominal current or current setting (I n ) does not
exceed the lowest of the current carrying capacities (Iz) of any of the conductors of the circuit. • The current causing effective operation of the protective device (I2) does not exceed 1.45 times the lowest of the current carrying capacities (Iz) of any of the conductors of the circuit. This may be summarised as: In --C.
12
INTERNAL EARTH FAULT ON ELITE PHASE
EARTH FAULI CuRkENT r e ,
PHASE VOLTAGE PHASE • EARTH/NEUTRAL EMPEDANCE
Flc. 6.31 Earth fault current path
It is considered that, in practice, earth fault currents are unlikely to exceed 2000 A and will probably be within the range 600-1000 A. For fuse protected circuits the clearance time for a given earth fault current can be determined from the fuse time versus current characteristic, enabling the armour temperature rise to be calculated. However, with aluminium armoured multicore cables to BS6346 it should be noted that the cross-sectional area of the armour wires is
462
IZ
1.45 lz
The circuit protection must operate with an overload up to 45 07o of rated current within a period accepted as being no more than 4 hours. While this more than doubles the conductor temperature rise, within this ti mescale, experience has shown that this does not result in unacceptable cable damage. The overload protection of plant items such as motors or transformers is provided by IDMT or thermal overload relays. With the protection set correctly, the characteristics of these devices meet this overload criteria. As the overload capability of the cable is normally greater than that of the plant item, this arrangement automatically affords overload protection to the cable. The protection of 415 V feeder circuits with fuses to BS88: Part 2 [8] also meets this cable overload criteria. Operation of the overload protection at not more than 1.45 times the current rating of the cable also applies to cables laid in ducts. With cables buried direct in the ground, the same rise in conductor temperature is reached with a smaller overload and therefore the maximum current at which the protection is designed
Power cable system design operate is required to be not more than 1.3 times he current rating of the cable.
to t
MOTOR STAR TING CURRENT
STARTING CURRENT
6 RA TEC SPEED
So
FULL LUAU CURHENT
Motor starting 4,4 ith motor circuits, cable sizing has to take account W f the starting condition as well as full load running. o to obtain information on the starting requirements of motors for power station use, reference is made to ESI Standard 44-3 [10] for 3.3 kV motors and boe and ESI Standard 44-4 [11] for 415 V motors. Both standards call for motors to comply with BS5000: part 40 [12], and for general applications a cage induction motor suitable for direct-on-line starting is provided. The standards also specify the frequency of ,tariing, stating that the motor shall be suitable for ‘‘, 0 starts in succession under specified conditions of Load, torque and inertia, with the motor at its normal running temperature followed by a cooling period of at least 30 minutes before attempting another starting sequence. The conductor temperature rise due to two successise motor starts increases with motor size. Typically at 415 V, the temperature rise is approximately 15 ° C 2 ° for a 5.5 kW motor (4 mm cable) and 50 C for a 2 150 kW motor (185 mm cable). It is first necessary to be able to calculate the conductor temperature rise due to motor starting. For calculation purposes it is convenient to regard motor starting as equivalent to a low value short-circuit and use the formula discussed earlier for this purpose. In practice this will give a slightly pessimistic result as some heat will he lost from the conductors with the longer durations involved. In order to apply the formula for short-circuit temperature rise, the starting current and duration must first be found.
J;)
d
TIP.1E - s
FtG. 6.32 Starting characteristic of a typical general
purpose induction motor
Motor starting performance is specified in kVA and expressed as a ratio where: Ratio -
rated output kW
ESI Standard 44-3 and 44-4 specify that the starting (locked rotor) kVA be in accordance with BS4999: Part 41 [13]. These are given in Tables 6.16 and 6.17 for the range of motor sizes/voltage level concerned. TABLE 6.16 415 V motor starting (locked rotor) ratio
Rated output, kW
Ratio
up to
2.5
10.5
2.5 up to
6.3
9.8
1
4.4.1 Motor starting current The starting characteristic of a typical general purpose nduction motor is shown in Fig 6.32. The standstill starting current (100 07o slip) at rated \ °Rage and frequency is termed the 'locked rotor current'. As can be seen, the starting current remains substantially equal to this value until the motor is up R.) approximately 80 07o of its rated speed. It is theretore convenient to assume that the starting current remains at the locked rotor current for the whole of he starting period, and to use this value for temperature rise calculation purposes. The rated output of a motor is the mechanical power 3 ,ailable at the shaft expressed in watts. For power station use, motor rated outputs are assigned to voltage le ,,els on the following basis: • 415 V — up to 150 kW. • 3.3 kV — 150 kW to 1800 kW. • 11 kV — 2000 kW and above.
starting (locked rotor) kVA
6.3 up to
16
9.2
16
up to
40
8.7
40
up to 100
8.2
100
up to 150
7.8
TABLE 6.17 3.3 kV and larger motor starting (locked rotor) ratio
Rated output, kW
Ratio
up to
250
6.0
250 up to
630
5.8
150
630
up to
1 600
5.6
1 600
up to
4 000
5,4
4 000
up to
10 000
5.2
For ratings in excess of 10 MW the ratio is required not to exceed 5.0 463
IP Cabling
Chapter 6
The full load current and starting kVA for a motor are given by: kW output x 1000 FL N13 x VL x x coso
TABLE 6.19 ,t fotor starting time Motor size, kW < 90
Starting kVA —
3+
Is x 3 x VL 90-450 [ 000
where: VL
Starting time s (empirical relationship)
(a) 15 s (b) large inertia motors, e.g., fan motors — guidance sought from motor manufacturer
li ne voltage, V
[FL Is
kW 7.46
> 450
full load current, A = starting (locked rotor) current, A
Guidance sought from motor manufacturer
= motor efficiency at rated load phase angle at rated load
4.5 Cable voltage regulation
Re-arranging the second equation and substituting for starting kVA gives: Ratio x kW output x 1000 vi 3 X VL
and by dividing the two equations for current x cosq5
IS/!FL = Ratio x
A starting current tolerance of +20% is permitted in B54999: Part 101 [14]. Hence, maximum starting (locked rotor) current 'ST is given by: IST = 1.2
'FL
x Ratio x
x cos4)
Currents are derived using average values of efficiency and power factor as given in Table 6.18.
TABLE 6.18 Average values for efficiency and power factor Rated output, kW 1
up to
2.5 up to 6.3 up to
6.3
% Reg —
(Vs — VR) x 100
Vs where Vs = nominal system voltage at supply end.
VR
=
voltage at receiving end.
All power station electrical plant and equipment is designed to operate within specified voltage regulation limits during steady state full load and under motor starting conditions, and consequently may not function or operate correctly if these limits are exceeded. These li mits are specified as: • Steady state full load, +6% and — 10% nominal system voltage.
0.78
0.80
• Motor starting, — 20% nominal system voltage for a period up to 90 s.
0.83
0.83
16
0.87
0.86
16
up to
40
0.906
0.88
40
up to
100
0.927
0.90
100
up to
250
0.94
0.91
250
up to
630
0.945
0.91
630
up to
1 600
0.95
0.91
1 600
up to 4 000
0.962
0.91
4 000
up to 10 000
0.973
0.91
4.4.2 Motor starting times
Motor starting times are determined on the basis shown in Table 6.19. 484
between the supply end and the receiving end due to the impedance of the system. For AC systems, the supply end is the feeder transformer secondary terminals, and the receiving end is the incoming terminals of the item of plant or equipment concerned. The voltage drop is normally expressed as a percentage of the nominal system voltage called voltage regulation, i.e.,
Power factor coscO
Efficiency
1.5
In any system carrying current, there is a voltage drop
At voltage levels above 415 V, voltage regulation only becomes a concern on the occasional circuit with a long route length. The main reason is that the denominator is now much larger, permitting a corresponding increase in voltage drop for the same value of voltage regulation. For example, for a voltage regulation of 3% at 415 V, 3.3 kV and 11 kV the permitted voltage drops are 12.5 V, 99 V and 330 V respectively. Ensuring that the voltage at the input terminals remains within these limits at 415 V is not just a single cable consideration. Voltage drop occurs across each series cable in a supply system, and therefore the voltage drop across any single cable must be some lower value in order that the total voltage drop remains
Power cable system design mits. Alternative distribution arrange-
thin these li be considered. ments must also To enable the system voltage regulations to be deterallowable steady state (this is not mined, the maximum full load as an allowance is made for necessarily at ity) and motor starting voltage regulations for ji , ers he main switchboards, motor control centres and dis:r[bution boards are set. The permitted voltage regulaa cable between any two items is the difference [on for k,-een the two assigned values of voltage regulation. A s an example, the voltage limits for a 415 V supply system are shown in Fig 6.33. This is based on
the 3.3 kV/0.415 kV transformer secondary voltage being equal to the nominal system voltage at steady state full load output, and is termed a voltage regulation profile. To calculate the voltage regulation in a cable it is first necessary to determine the voltage drop. For an AC circuit this is as illustrated in Fig 6.34.
, 3 3.. 3.61 TE 90ARD
Vs
STEADY STATE FULL LOAD • 6% TO MOTOR STARTING 1.6% TO -6%
No. 6.34 Cable voltage drop 6% TO
3 35V,8 15V TRANSFORMER
AV = [I(R cos0 + X sin4s) + V5(1 — cos)]
where AV = voltage drop, V I = current, I 6-.virCH B O A RD
= line angle
STEADY STATE FULL LOAD .6% TO - I% MOTOR TARTINO .6% TO - 11%
Vs = supply voltage, V R = AC resistance of conductor, ft cos cr3 = the power factor X = conductor equivalent star reactance at 50 Hz, The term V5(1 — coso) is very small and for simplification can be safely ignored. Therefore: MOTOR
▪ 6% TO - 10% +6% TO -20%
AV = ER cos i:// + IX sing) 0
and 70 R = 1001 (R cos 0 + X sinci5)/V 5 STEADY STATE FULL LOAD • 6% TO - 3 5% MOTOR STARTING r 64 TO - 14%
The maximum cable route length for a given size of cable and voltage regulation limit may be determined by expressing R and X in per unit length values and re-arranging the voltage regulation formula: • 6' TO - 10.5 TO -20%
Three-phase circuits
Lm Plc. 6.33 Voltage regulation profile
=
VL . .43 ( 100 1
10 R
0
(RL coo + XL Sin) 465
Cabling
Chapter 6
Single-phase circuits
TABLE 6.20 415 V motor starling power factor
(170 R Rated output, kW
Starting cos (1!)
2 (100 I (RL coso + XL sincs)) where L max
= maximum route length, m
V
nominal phase to neutral voltage, V
VL
= nominal line voltage, V R
permissible voltage regulation
RL
= AC resistance per metre at conductor operating temperature, Si/m
XL
=
conductor equivalent star reactance per metre at 50 Hz, cl/m
Values for conductor resistance and equivalent star reactance for single and multicore cables are given in Appendices A and B of this chapter. Feeder circuits When applied to 415 V fused feeder circuits, an allowance of 0.8 is made for load diversity. Therefore: I = 0.8 x fuse rating (I n ) cos(i) = steady state power factor Typically cos 0 = 0.85 for a mixed load and cosci) =0.99 for a resistive load, e.g., heaters. The conductor resistance is determined at the temperature corresponding to the above current I. Motor circuits With motor circuits, starting and full load operation are given by:
Motor starting
IST = motor starting current, A
cosq5ST = power factor on motor
starting Motor full load
IFL
full-load current, A
COSO FL = power factor at full load Values for cos q5 are given in Table 6.20.
For motor starting, the resistance of the conductor is determined at the temperature attained after two hot starts. For feeder circuits to switchboards and motor control centres, motor starting voltage regulation is based on the starting requirement for the largest motor on the switchboard or motor control centre. As previously stated, because of the repetitive nature of these calculations it is convenient to use tables for cable size selection. To achieve this, the formula is used to calculate the maximum cable route length for the minimum cable size to meet the full-load current/ 466
1
up to
2.5
0.26
2.5
up to
6.3
0,28
6,3
up to
16
0.30
16
up L O
40
0.27
up I O
100
0.23
100
up t o
150
0.20
protection requirements and for the next two larger cable sizes. These are tabulated for each feeder circuit fuse and motor circuit size for a range of voltage regulation values. A typical example is shown in Appendix H of this chapter.
4.6 Cable system design Having discussed the main technical requirements it is now time to see how these, along with certain additional requirements associated with maximum cable
route length, are applied. To assist, circuits are separated into circuit types, i.e., feeder or motor circuits, and these are then grouped according to the type of fault current breaking device employed. Under each of the headings, the applicable requirements are given and the basis for determining cable size is described. First, the cable size for normal full load operation is determined after the application of any rating factors. This cable size is then used to determine compliance with the remaining requirements. If necessary, the cable size is increased until a size in the range is found which complies with all the aPplicable technical requirements. Since cables are only available in a range of conductor sizes it is important to be clear about the term 'cable size'. This means the selection, from this range, of the cable with the smallest conductor size which meets the applicable technical requirements. There is an additional requirement for motor circuit cable sizing so far not discussed. This is that the cable must be able to withstand a short-circuit fault directly following the second hot start, i.e., the maximum short-circuit conductor temperature must not be exceeded under these circumstances. It is assumed that the time intervals between the successive starts and between the second start and the short-circuit fault are too short to allow conductor cooling. The temperature rise for this situation is calculated in a series of steps. To a reasonable approximation, the conductor temperature at normal full-load running is given by: Oft = OA + (OM — OA) (I FLIIC)2
Power cable system design .414.■•••■•■1■•■■■■■
v
conductor temperature at normal full load running, ° C _---_ ambient temperature, °C maximum conductor temperature for insulation, ° C normal full load running current, A
.here A FL 0A Ni [ L
cable current rating after application of any rating factors, A
IC
To a close approximation, the conductor temperature 'after two consecutive hot starts is determined from:
=
K25 2
log n Re 2ST + ONO FL +
a st where [sr to
02ST
starting current, A starting time, s conductor temperature after two consecutive hot starts, °C
(d) Single core cables Sheath voltages, plus current sharing if more than one cable per phase is used, are checked. 3.3 kV fused switching device
(a) Continuous operation
The circuit full load current is used to size the cable for continuous operation.
(b) Fault conditions A fuse to BS2692: Part 1 [6] of a rating which provides take-over from the switching device (see Chapter 5) is fitted to all feeder circuit switching devices. Short-circuit currents above a take-over current are cleared by the fuse, and below this take-over current are cleared by the switching device on operation of the circuit high set instantaneous overcurrent relay. If the fuse and relay protection characteristic curves are plotted together with the cable l 2 t value adiabatic line, in a similar manner to Fig 6.36, it can then be seen whether the cable is adequately protected. (c) Voltage regulation The cable size for steady state voltage regulation is checked.
The final conductor temperature following a short-
circuit fault is obtained from:
415 V fuse (a) Continuous operation The
2 2
K S =
0
logn Resc + 0)/( 2sT +
t sc
v,here Isc = short-circuit current, A tsc
duration of short-circuit, s
Osc = conductor temperature after short-
circuit,
°
C
If the final conductor temperature exceeds the insulation maximum short-circuit conductor temperature then the next larger cable size is tried.
4.6.1 Feeder circuits
first of the summarised circuit protection requirements given in Section 4.3.3 of this chapter may be expressed for a single cable as: design full load current fuse rating continuous current rating of cable. Cables are therefore sized to the circuit fuse rating. For design purposes, the full load current is normally taken to be equal to the fuse rating.
(b) Fault conditions
For economic reasons, local earth bonding is not normally applied to final 415 V feeder circuits at the plant equipment end (earthing is provided via the cable armour). In the event of an earth fault at the plant or equipment, there will be a local rise in potential with respect to any extraneous conductive parts which are separately earthed. This is shown in Fig 6.35.
Air break circuit-breaker (415 V, 3.3 kV and 11 kV) (a) Continuous operation
CEGB policy for large feeder circuits is to size the cable to the current rating of the circuit-breaker rather than the circuit design full load current. This approach affords the maximum allowance for design uncertainty and possible future development.
JNTERNAL FAULT RESULTS IN LOCAL RISE IN EARTH POTENTIAL TRANSFERRED POTENTIAL
FEEDER CABLE
ft-4
PLANT ITEM
DSTRIBUTION BOARD
EXTRANEOUS METAL WORK P9 PIPE
(b) Fault conditions
Short-circuit minimum crosssectional area is determined for the back-up protection fault clearance time. This needs to be determined for each individual case.
(c) Voltage regulation
The cable size for steady state voltage regulation is checked for 415 V and 3.3 kV circuits.
CONNECTION FROM CABLE GLAND BODY TO EARTH PLANT ITEM
FIG. 6.35 6.35 Local rise in earth potential 467
Cabling
Chapter 6
As this may give rise to transfer potentials in excess of 55 volts, it is necessary to ensure that the protection operates in a time not greater than 460 ms (see Section 11.2.2 of this chapter). The minimum fault current to achieve this clearance ti me can readily be determined from the fuse time versus current characteristic. The earth fault current is determined by the earth loop impedance which, in turn, is a function of cable route length and therefore for a given cable size there is a safe maximum route length. To simplify the calculation of this length, the source impedance and cable reactance (the cable sizes involved are normally less than 35 mm 2 ) are assumed to be negligible. Expressing resistance in terms of per metre length gives: V 'EF
therefore L,-,-, a , -
P
L(R., + Ra)
Ra )
where Lmax = maximum route length, m 'EF
= earth fault current that will interrupt BS88: Part 2 [8] fuse in 460 ms, A = conductor resistance per metre at full load operating temperature, Cl/m
Ra
= armour resistance per metre at
ambient temperature plus half the conductor temperature rise from ambient to full load operating temperature, Wm VP
phase voltage, V
In this instance R, and R a are calculated for the
full load current concerned. The temperature rise due to the earth fault current is assumed to be negligible. Cable armour resistances are given in Appendix B of this chapter. If the maximum route length to operate the protection in 460 ms is found to be shorter than the circuit route length, then the next larger size cable is tried, until a suitable cable size is found. If the earth fault had occurred on energising the circuit, the cable conductor and armour would initially be at ambient temperature. Consequently, the resistance values would be lower than for the full-load operating condition, shortening the fuse operating time. (c) Voltage regulation The cable size for steady state and motor starting voltage regulation is determined as described in Section 4A of this chapter. 468
Air break circuit breaker (3.3 kV and 11 kV) -
(a) Continuous operation
The motor rated full load current is used to size the cable for continuous operation.
(b) Fault conditions
This requirement normally dictates the circuit cable size, as clearance of short-
circuit current is based on the back-up protection operating time. Typically, back-up protection on a 3.3 kV switchboard is provided by the incoming transformer feeder high set instantaneous overcurrent relay on the 11 kV switchboard which, to allow for grading with the largest 3.3 kV outgoing circuit, would operate in about 0.6 s. (c) Voltage regulation Motor starting and steady state voltage regulation are checked at 3.3 kV. (d) Single core cables Sheath voltages, plus current sharing if more than one cable per phase is used, are checked. -
240 'EF (R c
4.6.2 Motor circuits
3.3 kV fused switching device
(a) Continuous operation The motor rated current determines the cable size for continuous operation. (b) Fault conditions A motor starting fuse to BS5907 [7] is fitted to all motor circuit fused switching devices. Short-circuit currents above the switching device take-over current are cleared by the fuse, while those below this value are cleared by the switching device as explained for 3.3 kV FSD feeder circuits. Back-up protection in the zone covered by the circuit high set instantaneous overcurrent relay is provided by the fuse and the incoming feeder circuit or interconnector high set instantaneous overcurrent relay also as previously described. The cable 1 2 t value is determined after two consecutive hot starts for a temperature rise up to the maximum short-circuit conductor temperature. As before, the cable I 2 t value adiabatic line is superimposed on the fuse and protection coordination curves to determine whether cable shortcircuit protection is provided. This is shown in Fig 6.36. (c) Voltage regulation Motor starting and steady state voltage regulation are checked. 415 V fuse/contactor (a) Continuous operation
The motor rated full load current is used to size the cable for continuous operation.
(b) Fault conditions
Motor circuit contactors are to BS5424 1161 Category AC-3 which have a breaking capacity of 8-times rated operational current
Power cable system design
KEY ADD' TIONAL PROTECTION GIVEN BY INSTANTANEOUS OVERCURRENT RELAY
- THERMAL RELAY .COLD,
THERMAL RELAY (HOT)
CABLE 1 2 1 ADIABATIC FROM AMBIENT)
CURRENT II ADIABATIC (AFTER TWO HOT STARTS)
FUSE CHARACTERISTC
MAIN PROTECTION HrGH SET INSTANTANEOUS OVERCURRENT RELAY MOTOR STARTING CHARACTERISTIC I
•^{)
I
1
1 1. 11
I
I
I
1 0000
1' 000
1 004300
CURRENT -AMPS
Flu. 6.36 3.3 kV Fuse switching device protection characteristic for a motor
for sizes up to 100 A and 6-times rated operational current for sizes in excess of 100 A. Contactors therefore, are unable to interrupt heavy fault currents and protection of the motor and cable under these conditions is provided by fuses. Contactor circuit fuses comply with BS88: Part 2 (81 and operate within a specified fuse time versus current zone. This is contained by the minimum
pre-arcing time versus current characteristic and the maximum total operating time versus current characteristic and includes a ±10 67o tolerance. The fuse size is selected on the basis of the maximum starting current and twice the maximum starting time to allow for two consecutive hot starts. This generally requires the fuse rating to be higher than the continuous current rating of the cable required for full-load running. Separate thermal Overload protection is provided for 1.5 kW motors and larger. Thermal overload relays comply with RS142 [17] which makes reference to manufacturer's data for the operating characteristic. For motors up to 15 kW, relays with direct connected elements are used and, above 18.5 kW, current
transformers are used. The operating characteristic depends on the initial temperature of the relay. After two hot starts the characteristic is said to be 'hot' and on initial starting said to be 'cold'. Motor starting requirements, fuse time versus current characteristic and a typical thermal overload characteristic are shown superimposed for a typical motor in Fig 6,37 (a). To ensure that the maximum short-circuit conductor temperature is not exceeded, the extrapolated 1 2 t adiabatic line after two hot starts and for initial starting are also superimposed on the figure for the cable conductor temperature rise concerned. The worst possible overload condition corresponds to the point nearest the cable I 2 t adiabatic line. This is either the intersection of the thermal relay 'cold' characteristic and the upper limit of the fuse operating line with the cable ambient 1 2 t adiabatic, or the intersection of the thermal relay 'hot' characteristic and the upper limit of the fuse operating time with the cable 'two hot starts' 1 2 t adiabatic line. It can be seen that the adiabatic line must cross at or above the intersection of the thermal relay and fuse characteristic for the cable to be protected. It can be seen in Fig 6.37 (b) that an area is left unprotected, demonstrating that a larger cable size is required. Appendix G gives motor parameters and the selected fuse size for each CEGB standard motor size. For earth fault protection, motors larger than 50 kW are provided with sensitive earth fault protection relays. Earth fault currents above a takeover current are cleared by the fuse and below this current by the contactor on operation of the earth fault protection relay. Motors below 50 kW are not fitted with sensitive earth fault protection and as a consequence it is required that earth faults are cleared by the fuse. The minimum fault current to interrupt the fuse without damage to the cable is obtained from the intersection of the cable I 2 t adiabatic and the upper limit of the fuse operating time. In practice if the cable has been accurately sized for motor starting and short-circuit phase faults, its adiabatic line will cross the fuse characteristic close to its intersection with the thermal overload relay. Since the current and time durations for this intersection must he known, as already described, it is convenient to also use these values to assess earth fault conditions. The limiting condition is invariably with the thermal relay hot, as shown in Fig 6.38. For the appropriate minimum current to flow, the earth loop impedance must be less than a value which corresponds to the maximum route length. Although earth fault current may return through other paths to the system neutral, the worst case for the cable is when it all returns through the 469
IP" Cabling
Chapter 6
KEY 000
AREA WHERE CABLE NOT FULLY PROTECTED
1000
FUSE CHARACTERIST.0 ZONE)
FUSE CHARACTERISTIC ,ZONE1
OvEr,LCAD
C,.ARACTERiSTiC
aj CABLE PROTECTED
(SI CABLE NOT FULLY PROTECTED
ToviE - s
2 STARTS
I START
RELAY 'COLO .
RELAY COLO'
RELAY 'ROT' RELAY HOT'
CABLE 1 2 1 ADIABATIC FROM AMBIENT, CABLE 2, ADIABATIC :AFTER TWO HOT STARTS1
I S
MOTOR ^ STARTING CHARACTERISTIC
CABLE 1 2 1 A01ABATic FROM AMB , ENT i2
ADIABATIC CABLE ,AFTER TwO HOT STARTS1
or
0 1
0/
I
1
I
1
1
0.01
1 1 1
10
100
1 0000
1 L
10000
CURRENT-AMPS
FIG. 6.37 415 V motor starting, fuse time versus current, thermal overload, short-circuit characteristic
cable armour. The maximum route length can therefore be determined using the same expression as used for feeder cable maximum route length, i.e., max
240/IEF (Rc
Ra)
where L max = maximum route length, m minimum earth fault current, A
'EF
=
R,
= conductor resistance per metre at full-load operating temperature, S2/m
Ra •
= armour resistance per metre at full-load operating temperature, 11/m
The same assumptions regarding source impedance and cable reactance are made as before. (c) Voltage regulation Voltage regulation requirements for steady state and motor starting conditions are checked as described in Section 4.4 of this chapter. 470
4.7 Practical examples To illustrate the steps followed during power cable system design, a worked example is given for a feeder and motor circuit at each system voltage. 4.7.1 Feeder circuits
1/ kV interconnector An 11 kV interconnector circuit is required to carry a full-load current of 2200 A, The rating of the circuitbreaker at both ends is 2400 A. The back-up protection clearance time is 1.0 s. The cables are to be installed in air at an ambient temperature of 35 ° C with a route length of 80 m. Access to CURE103 (see Section 4.2.6 of this chapter) is available. Determine a suitable cable arrangement. (a) Continuous operation The continuous current ratings of 11 kV single-core cables laid in air at an ambient temperature of 25 ° C are given in Appendix C as: Single-core 300 mm 2 — 675 A Single-core 500 mm 2 — 900 A
Power cable system design
F tiSt `.7...IRACTV1ISr.0
(b) Fault conditions The minimum cable cross-sectional area required under short-circuit conditions with a back-up protection clearance time of 1.0 s is given in Table 6.14 as 417 mm 2 . Short-circuit requirements are therefore met.
,ZONE!
(c) Voltage regulation As the cable route length is relatively short it is most unlikely that voltage regulation would be a concern. The voltage drop calculated using CURB03 is 38 V corresponding to a voltage regulation of 0.63/4. (d) Sheath voltage The standing sheath voltage is given by CURB03 as 20 V which is well within the 55 V acceptance limit. To determine the sheath voltage occurring due to a through fault, the formula given in Section 4.2.6 of this chapter is used, i.e.,
PELAY COLa
Vsc
RELAY HOT
= V s X ISC/IFL
= 20 x
39 400 2 400
L
= 328 V which is less than the 2 kV acceptance limit
wAn ,- HAAuLT pap.1 'C 'NrEIRURT
In conclusion, three single-core 500 mm 2 cables per phase are required.
ti I
I
I
I
I
I E l i
1. 0000
1000
100 CURRENT AMPS
Fiu. 6.38 Minimum earth fault current to
interrupt fuse
The rating factor for an ambient temperature of
35°C is given in Appendix E as 0.91. Applying this rating factor gives: •;ingle - eore 300 mm 2 — 614 A
sirwle.-Qore 500 mm
2
(675 A x 0.91 = 614 A)
— 819 A (900 A x 0.91 -= 819 A)
Me cables are NiZeCi to the rating of the circuitbreaker (see Section 4.5.1 of this chapter) and by electing the larger cable size, three cables per phase appear to be suitable, i.e., 3 x 819 A = 2457 A, provided current sharing is satisfactory. Inputting cable details, co-ordinates of the route ectior. ts with cable transposition, and the current into CURB03 produces the following output:
3.3 kV/0.415 kV transformer A 2 MVA 3.3 kV/0.415 kV AN transformer is to be supplied from a 3.3 kV switchboard using a circuitbreaker with a rating of 800 A. The back-up protection clearance time is 1.2 s. The cable route length is 500 m, part of which is in air at an ambient temperature of 25 ° C and part buried direct in the ground having a thermal resistivity of 1.5 K.m/W and a temperature of 15 ° C. The ground in one section has recently been made-up but is otherwise of average consistency. The depth of burial is 0.8 m except in the made-up ground where this is increased to 1.25 m. The maximum duct length when passing through walls is 300 mm. Determine the cable size required: (a) Continuous operation The continuous current ratings of a 3.3 kV single core 400 mm 2 cable laid in air at 25 ° C and in the ground at 15 ° C taken from Appendix C are: Laid in air
— 785 A
Buried direct in ground
— 575 A
,
= 818 A = 795 A
= 780 A
R2 =7 802 A
R3
Yi = 790 A
Y2 = 815 A
Y3
B 1 = 789 A
B2 = 795 A
83 = 816 A
From examination, the currents in each cable are all less than 819 A.
Account does not need to be taken of the short length of cable passing through ducts (see Section 4.2.4 of this chapter) but rating factors need to be applied for the ground thermal resistivity and for the increased depth of burial. The soil thermal resistivity is 1.5 K.m/W and from Appendix E the rating factor for this is 0.91. 471
Cabling
Chapter 6
The rating factor for a depth of burial of 1.25 m is given in Appendix E as 0.95. Applying these factors to the rating of the cable buried direct in the ground gives: 575 A x 0.91 x 0.95 = 497 A The cable rating in ground is lower than that in air and is therefore the limiting factor. Since the cables are sized to the rating of the circuit-breaker, 2 x 400 mm 2 cables per phase are required. Current sharing for the proposed installation arrangement is satisfactory if installed as shown in Fig 6.25. For the purpose of this example, it is assumed that the spacing between the two sets of cables for the route sections buried in ground is sufficient to avoid group rating. (b) Fault conditions The minimum cable cross-sectional area required for a short-circuit fault with a back-up protection clearance time of 1.2 s is given in Table 6.14 as 507 mm 2 . Short-circuit requirements are therefore satisfactory with 2 x 400 mm 2 cables in parallel. (c) Voltage regulation This is checked using CURB03 and for this example is taken to be satisfactory. (d) Sheath voltage The sheath voltages are checked in the same way as shown in the previous example and, for the purpose of this example, are assumed to be satisfactory.
(b) Fault conditions The maximum allowable route length under fault conditions is given by: L max = 240/IEF (Rc +
From the 63 A fuse characteristic in BS88: Part 2, to interrupt the fuse in 460 ms requires a fault current IF of 640 A. To obtain the conductor and armour resistances we must first calculate their operating temperatures using the formula given in Section 4.6 of this chapter: Conductor temp OFL = OA + (Om A)( 1 Ftilc) 2 35 + (70 — 35)(63/92) 2 —
0
= 35 + 16 = 51 ° C The armour temperature rise is taken to be half the conductor temperature rise: °FLA = OA + 16/2 = 35 + 8 = 43 ° C For multicore cables up to 300 mm 2 , skin and proximity effects (see Section 4.2.3 of this chapter) are negligible and therefore the AC resistance is taken to be the same as the DC resistance. From Appendix B:
In summary, two single-core 400 mm 2 cables per phase are required.
Rao = 868 /40/m;
415 V three-phase and neutral (TPN) distribution board feeder
Conductor resistance Re
A supply to a 415 V TPN distribution board is protected by a 63 A fuse. The cable is laid in air at an ambient temperature of 35 ° C with a route length of 85 m. The power factor is to be taken as 0.85 and the maximum allowable voltage regulation is no. Determine a suitable cable size.
Ra)
Ram = 960 pl//m and for aluminium a20 = 0.00403.
= Rao [I + Ct20 ( 0 FL —
20
)1 = 868 [1 + 0.00403 (51 — 20)] = 9764/m Armour resistance R a Ran [1 + cr2o (0 FLA — 20)1 = 960 [1 + 0.00403 (43 — 20)]
(a) Continuous operation The continuous current ratings for 4-core 16 mm 2 and 35 mm 2 cable sizes laid in air at an ambient temperature of 25 ° C are given in Appendix D as:
= l049 NOW L m
2/m
240 x 10 6 =
4-core 16 mm 2 — 65 A
—
185 m
640(976 + 1049)
4-core 35'mm 2 — 104 A
With a 35 ° C ambient temperature, the rating factor from Appendix E is 0.88, giving: 4-core 16 mm 2 — 57 A
(65 A x 0.88 = 57.2 A)
4-core 35 mm 2 — 92 A
(104 A x 0.88 = 91.5 A)
On the basis of a full load current of 63 A, the 4core 35 mm 2 cable size is initially selected. 472
This value is greater than the actual route length of 85 m. (c) Voltage regulation The maximum cable route length for a given voltage regulation is given by: VL
olo R
L max — ( 100
x 0.8 x I n (RE cost')
XL Sind)))
Power cable system design Values for RL and XL are taken from Appendix B. Correcting resistance for temperature at 0.8 I n gives: ° C and XL = 82 ) 4C2/m RL = 959 tz12/rn at 46
substituting
Substituting in the equation gives: 415 L max ------ 7Ni 3 -
The conductor temperature after two hot starts is given by: K2s2 1 1T - - loge [( 0 2S1 + 0)/(OFL + (3 )1 2t 51 (148) 2 x (300) 2
(1021) 2 -
(40 + 228)] 2 x 10 6
0.042
(100 x 0.8 x 63(959 x 0.85 + 82 x 0.53)
)
=
log, [(0251 + 228)/268]
280 = 02sT + 228
02sT = 52 ° C
= 111 m Again, this value is greater than the actual route length m. In summary, a 4-core 35 mm 2 cable is of 85 required.
Finally, to calculate the conductor temperature after a short-circuit fault:
K 2S 2
Iic
tsc
4.7.2 Motor circuits
log o KOSC + (3)/( 0 2ST
+ 0)]
substituting
11 kV motor -s, n 11 kV ID fan motor has a rating of 3 MW. The
motor manufacturer has given a ratio of locked rotor kVA to rated output of 5.4 and a starting time of 40 seconds. The cable route length is° 100 m and is in air at an ambient temperature of 35 C. Determine the ,: able size required. The back-up protection operating ti me is 0.7 S. From Table 6.18 77 = 0.962 and cos ci) = 0.91 for a 3 MW motor. The full-load current is given by kW output x 1000 'FL —
x VL x i, x cosit,
substituting -
l o g o RO2ST + 228)/
2 x 40
x
3000 x 1000
- 180 A
N/3 x 11 000 x 0.962 x 0.91 The maximum starting current
1ST = 1.2 x 'FL X ratio x x cos0 = 1.2 x 180 x 5.4 x 0.962 x 0.91 = 1021 A (a) Continuous operation The current rating of a single-core 300 mm 2 cable laid in air is given in Appendix C as 675 A at 25 ° C. At 35 ° C the current rating
= 675 x 0.91 (from Appendix E) = 614A (b) Fault conditions The conductor temperature
during normal full-load operation is given by: °FL = 0A + (0),4 - OA) x (IFL/Ic)2
substituting = 35 -4-(90 - 35) x (180/614)2 = 40 ° C
(39.4 X 10 3 ) 2 —
(148) 2 x (300) 2
log, [(Osc + 228)/
0.7 (52 + 228)] 0.551 = log, [(t3sc + 228)/280] 486 = esc 228 ° es c = 258 C Although the conductor temperature is 8 ° C too high, in reality there would be some conductor cooling during the sequence of events described and therefore a judgement is taken that the 300 mm 2 size cable is satisfactory. There is no transposition and therefore the standing voltage on the middle cable is given by:
(c) Sheath voltage
Vs = 47rft 10
-7
1og (s/r) V/m
Taking the armour radius for a 300 mm 2 cable as 18 mm and substituting V s = 4 X 7r. x 50 x 180 x 10 -7 x log r, (80/18) = 0.017 V/m The magnitude of sheath voltage on the outer cables is given by: -7 [(2 log, (V2 x s/r) 2 + 1 Vs = 2r fl 10
1.44] 2 = 2 x r x 50 x 180 x 10 -7 x [ (2 log , Oh x 80/18)) 2 + l.44]2 I V s = 0.022 V/m 473
1P01"
Cabling
Chapter 6
As the cable length is 100 m, the standing voltage on the centre cable is 1.7 V and on the two outer cables 2.2 V, and is therefore satisfactory. During a short-circuit fault the sheath voltage is given by:
The conductor temperature after two hot starts is given by: K2S2 3 2 — logo Re2ST + i )/(.0Ft + 3)] (IST) 2tst
substituting Vs c = V s x
, (365)2 —
(148) 2 x (150) 2
substituting for outer cable Vsc = 2.2 x 39400/180
(27 + 228)]
e 2ST
— 482 V The short-circuit sheath voltage is less than 2 kV and is therefore satisfactory.
I 2 t = K 2 S 2 log, [(Or + 3)/(Ot + 3 )1 --- (148) 2 x (150) 2 log, [(160 + 228)/ (29 + 228)]
3.3 kV motor A 3.3 kV pump motor has a rating of 300 kW. The supply is taken from a 3.3 kV FSD with a 400 A fuse. The motor manufacturer has quoted a starting time of 15 seconds. The cable is to be laid in air at an ambient temperature of 25 ° C and a route length of 110 m. Backup protection is provided by the fuse in the zone protected by the high set instantaneous overcurrent relay. Determine the size of cable required. From Table 6.18, t = 0.945 and cos (/) = 0.91 and from Table 6.17 the motor starting ratio = 5.8. The full load current is given by: kW output x 1000
▪
x VL x x cost)
▪
= 203 x 10 6 The short-circuit I 2 t adiabatic line is superimposed on the fuse time versus current characteristic as shown in Fig 6.36. For the purposes of this example it is assumed that the cable is protected. (c) Voltage regulation The motor starting voltage regulation is obtained first. The conductor resistance at the end of two hot starts temperature from (b) is 29 ° C. From Appendix B, for a 150 mm 2 cable at 20 ° C the conductor resistance is 206 /.4.11/m and the equivalent star reactance is 80 giI/m. From the manufacturer, power factor cogb on starting is 0.5. Conductor resistance RL
300 x 1000
[1 + a20(02ST — 20)] = 206 [1 + 0.00403(29 — 20)] = Rc20
x 3300 x 0.945 x 0.91
'FL = 61 A
= 213
The maximum starting current = 1.2 x FL x ratio x
G/o R
x cos 43
1.2 x 61 x 5.8 x 0.945 x 0.91 = 365 A (a) Continuous operation The smallest three-core 3.3 kV cable in the standard range is 150 mm 2 (because of short-circuit requirements) and it can be seen from Appendix C that this has a rating of 265 A in air at 25 ° C. (b) Fault condition The conductor temperature during full-load operation is obtained from: 0
FL = OA + (OM — OA) (I FL /iC) 2 25 + (70 — 25) (61/265) 2 =27 ° C
474
° = 29 C
The 1 2 t adiabatic line for a short-circuit temperature rise from 29 ° C to 160 ° C is now determined from:
In summary, one 300 mm 2 single-core cable per phase is required.
'FL —
log, [(02sT + 2281/
2 x 15
itf2/m
= 100 IL (RL cosy& + XL sin) .s./3/ 14.
= 100 x 365 x 110 (213 x 0.5 + 80 x 10_6 x V3/3300 0.87) = 0.37% This regulation is small compared with the 20% allowed at motor terminals during starting and therefore is acceptable. Because of the small value of regulation during starting, in this case there is no need to check the regulation under full load conditions. In summary a three-core 150 mm 2 cable is required. 415 V motor A 3 kW 415 V pump motor fed from a 415 V contactor starter has a cable route length of 80 m. The cable is
Power cable system design ° to be laid in air at an ambient temperature of 35 C. The maximum allowable voltage regulation on starting Ira and on full-load 3.5%. Determine the cable i, .1ze. ‘ppendix (.1, the maximum starting current rriilmotor is 49.1 A with a full-load current a The starting time is 3.4 s and the selected 1 A,
K 2S 2 — loge ROscc + t3)/(0A + .3)1 (226) 2 x (2.52) 2
(35 + 234.5)1
6.
,ize is 32 A. operation The current rating for a COnfiIIIIOUS ° C is given in 1-core 2.5 mm cable in air at 25 Appendix C as 28 A. In an ambient temperature a rating factor of 0.88 is applied as given ° of 35 C in Appendix E. Therefore the cable current rating i s 24.6 A which is in excess of the motor fullload current of 6.1 A. The conductor temperature during normal full-load operation is given by:
(b) Fault conditions
0A)(iFt/ic) OFt = OA + Rom = 35 + 1(70 — 35)(6.1/24.6) 2 1 2
—
]
= 37 ° C The conductor temperature after two hot starts is obtained next: K2S2 ST
(49.1) 2
—
loge RezsT + 0)/(OFL + 13)1
° Oscc = 136 C
Since both escH and Oscc are lower than the cable short-circuit temperature of 160 ° C the size is satisfactory from this aspect. Finally it is necessary to check the maximum route length that will allow sufficient earth fault current to flow to clear the fuse using the method given in Section 4.6.2 of this chapter. From Appendix B, the conductor and armour resistance at 20 ° C are 7410 Aft/m and 8800 respectively. From (b), the full-load conductor temperature is 37 ° C and, taking the armour temperature rise to be half that of the conductor, gives an armour temperature of 36 ° C. Correcting the resistances to these temperatures gives R, = 7905 Aim and R a = 9434 A-2/m. Also from (b) the intersection of the fuse and thermal relay (hot) characteristics give IF = 160 A. Therefore:
2t s1 (226) 2 x (2.5) 2 2 x 3.4
240 log o RO 2ST + 234.5)/
1F (Rc + Ra) 240 x 10 6
(37 + 234.5)1 . 02yr
log ROscc + 234.5)/
6
160 (7905 + 9434)
51 ° C
= 87 m
The next step is to check the conductor temperature OscH for a fault immediately after two hot starts. The maximum fault let through is taken from the intersection of the fuse and thermal relay (hot) characteristics. For a 3 kW motor with a 32 A fuse this gives Isc H -= 160 A and t = 2.3 s. K 2S 2 logo RescH + 3)/(02sT + (226) 2 x (2.5) 2
log e [(Elsa/ + 234.5)/
2.3 (51 + 234.5)1 OSCH
109 ° C
Then the conductor temperature for a fault with the cable at ambient must be checked. The maximum fault let-through is taken from the intersections of the fuse and the thermal relay (cold) characteristics. For a 3 kW motor with a 32 A fuse this gives 1 = 130 A and t = 6 S.
Since this maximum route length exceeds the actual route length, the cable is adequately protected against earth faults. (c) Voltage regulation The voltage regulation during normal full-load operation is generally a more onerous condition than during starting and therefore the former is calculated first. From (b), the conductor resistance at full-load conductor temperature R1 = 7905 it.O/In and from Appendix B, XL = 100 ASZ/m. From Table 6.18 for a 3 kW motor, cos cb = 0.83. From Section 4.5 the maximum route length: Lmax =
VL
0
x
70R
100 x I (RL coscb + XL sings) =
3.5 x 10 6
415 13
x
( 100 x 6.1(7905 x 0.83 + 100 x 0.56)
= 208 m 475
WP" Cabling
Chapt er 6
The motor starting voltage regulation is calculated using the conductor temperature after two hot starts which from (b) is 51 ° C. Correcting the conductor resistance for this temperature gives RL = 8313 A/m. From Table 6.20 the motor power factor during starting, cos 0= 0.28. Now:
11 x 10 6
415 .13
( 100 x 49.1 (8313 x 0.28 + 100 x 0.96) )
= 222 m
These maximum lengths for voltage regulation are both considerably in excess of the actual route length of 80 m. In conclusion, a 3-core, 2.5 mm 2 cable is required to supply this 3 kW motor. In this example, the limiting factor for route length is the requirement to ensure sufficient current flows during an earth fault to operate the fuse. As discussed under 415 V fuse/contactor in Section 4.6.2 of this chapter, the accurate but more time-consuming method for obtaining the minimum earth fault current is to construct the cable I 2 t adiabatic line (hot) on the relevant fuse characteristic. This will invariably give a longer route length and may be worthwhile determining in instances where this requirement dictates the conductor size. 5 Control and instrumentation cable systems This section deals with the cabling systems that are necessary for the following functions: • Control and instrumentation. • Protection, intertrips and interlocks. • Metering. • Telecommunications. • Alarms. • Computers and data logging equipment.
5.1 Signal levels The types of signal being considered can be broadly split into two classes: (a) Analogue signals consisting of voltages that vary relatively slowly and currents such as those present in transmitter outputs (e.g., 4-20 mA), thermocouple outputs (e.g., 0-40 mV) and position indicating potentiometers (e.g., 0-10 V). They also include current transformer (CT) and voltage transformer (VT) circuits for instrumentation. 476
(b) Digital signals defined as voltages or current whi c h are normally at one voltage or another with a relatively rapid change between states. Examples are plant orientated alarm signals, sequence control input and output signals (e.g., 0-48 V). They also include switched 110 V DC and 110 V AC circuits.
5.2 Cable types For convenience the cable types used for these classes of signals can be split into three categories: (a) Multipair control cables (as described in Section 3.6 of this chapter) which are suitable for use at voltages up to 110 V AC or 150 V DC. However, these cables should not be used for circuits which contain unsuppressed 110 V AC contactor or relay coils of such a rating that they are likely to give rise to switching transients that are in excess of the 2 kV test voltage. These cables have a cross-sectional area of 0.5 mm 2 and it is recommended that the maximum current in any conductor be limited to I A, and that no more than 40% of the pairs be loaded with this current at one time. (b) Multicore control cables (as described in Section 3.5 of this chapter) which are rated at 600/1000 V and have a conductor cross-sectional area of 2.5 mm 2 . These cables are used where the circuit voltage (continuous or transient) or circuit current is in excess of the capabilities of multipair cables. However, these cables are more expensive and also more prone to interference (see Section 5.3 of this chapter) and should not be used unless essential. (c) Special cables such as coaxial, triaxial and low loss individually screened pair cables are necessary for particular applications. The performance of such special cables is normally prescribed by the plant contractor involved and they are frequently provided by him as free issue for the cable contractor to install. One problem with many of these special cables is that they are normally not armoured and are therefore unable to withstand the rigours of installation and service in a power station environment; so, in many cases, it is necessary to provide mechanical protection by conduit or trunking.
5.3 Cable interference This section is intended to give an insight into basic interference theory which will be found useful in understanding why it is important to give careful consideration to signal types and the type of cable to which they are allocated. Table 6.21 contains the abbreviations, descriptions and units that will be used throughout the following interference theory.
'
Control and instrumentation cable systems TABLE 6.21
Descriptions and abbreviations used in interference theory Unit
Description Nlagnetic flux density
Webers per square (Wb/m 2 )
metre Permeability of free space 4T
Henries per metre (H/m)
Cur ent through conductor
Amperes
( A)
Electric field strength
Voits per metre
(V/m)
Charge per unit length
Coulombs per metre
( C/m)
Permittivity of free
Farads per metre (F/m)
,
CfpNOLIC TOR 15
CARRYING AMP ATO PLANE OF PAGE;
space
V
Frequency
Hertz
( Hz)
Voltage
Volts
( V)
5.3.1 Interference in multipair cables Bay current carrying conductor produces a magnetic field and an electric field. If we consider the hypothetical case of an isolated single conductor, see Fig 6.39, it will be surrounded by a magnetic field inchated by the dotted lines and an electric field indicated by the solid lines. The spacing of the lines gives an indication of the relative strength of the field, where they are close it is high and where they are far apart it is low.
It can be shown that the magnetic flux density and electric field intensity at any point are inversely proportional to the distance away from the conductor:
FiG. 6.39 Magnetic field around an isolated
single conductor
(a) Magnetic flux density at a point P, r metres from the centre of the conductor is Webers/m 2
B= 2-rr
(b) Electric field intensity E—
V/m e2rr
These two expressions show how B and E decrease as r increases. If we now consider a balanced pair of conductors, i.e., carrying equal and opposite currents (see Fig 6.40),
Fic. 6.40 Magnetic field for a balanced pair of conductors 477
Cabling
Chapter 6
in the same way expressions can be stated which give the magnetic flux density and electric field strength. It can be shown that the magnetic flux density and the electric field strength at any point P vary as the inverse of the square of the distance between P and the cable system centre. In fact the field strengths at P1 and Pi will not be identical when ri and r2 are equal because of the geometry of the arrangement, but providing that r is considerably larger than d (conductor diameter), then this approximation may be made. In our calculations we will be able to assume, generally, that r is greater than d and so the simplification will be invoked: (a) Magnetic flux density at a point P, r metres from the centre of the twin system. = Ald 71
(6.3)
.r 2
(b) Electric field intensity at point P E
qd
(6.4)
Note the two implications of these formulae; firstly the flux density and field intensity vary inversely with the square of the distance from the system (and not directly as the inverse of the distance as in the isolated
conductor case), and secondly that the smaller d is made the smaller the flux density/field intensity at a given point becomes. Before we turn from looking at the magnetic/electric field produced by current carrying conductors to the interference induced in other conductors by those fields, there is one further point to consider. The last example considered long, straight, parallel conductors. If we twist those conductors to form a twisted-pair then there is a cancellation of the magnetic/electric fields which is most easily explained by the diagram shown in Fig 6.41. Field at P due to A is cancelled by that due to B C is cancelled by that due to D E is cancelled by that due to F, etc. Assuming the twisted cable to be made up of very short, straight lengths joined by transpositions it can be shown that (for short enough parallel lengths) the magnetic and electric fields, at a point P outside the cable will each be cancelled.
Since we are dealing with a twisted pair, there ar e many small geometrical considerations which will affect the amount of cancellation and thus there will b e residual fields. These considerations include conductor geometry, twinning lay and spacing variation. It is usual to apply a reduction factor of about 10 for the case of a normal twisted-pair cable compared with a straight parallel-pair. We shall now consider the way in which the magnetic field produced by (a) a single conductor and (b) a pair of conductors, affects another pair of conductors in their vicinity. In both cases straight parallel conductors are considered initially, the reduction factor above being applied at the end of the calculation. In this situation we are primarily concerned with the magnetic coupling between the two circuits since we are working at normal power frequencies. Electrostatic coupling becomes more important as frequency rises (l0 4 kHz and above), but at mains frequency magnetic coupling dominates. Referring to Fig 6.42, the induced voltage on a pair is a function of the magnetic field cutting them which in turn depends on the separation of the pair, their mutual separation from the current carrying conductor and other geometric considerations. Mathematically the amount of flux linking the cables may be found in several ways. To do this exactly is a relatively complicated procedure, but an approximation may be made by finding the average flux at the centre of the pair and assuming this to be constant over the area between them (safe assumption if d is small). To find the total flux cutting the pair per metre, we must then multiply this average by (2d x 1) square metres which is the area enclosed by a 1 metre length of the pair. The voltage induced on the pair is then proportional to this flux and its rate of change, i.e., frequency. The induced voltage per metre is given by: V = 27rf x
(6.5)
x (2c1 x 1) 27rR
rate of change x mean flux x area which simplifies to V— 2Adfl
(6.6)
The basic implications of this are that as we make d smaller and/or R larger the induced voltage drops.
•P
71
/ \
1 4_1
4
IN•
,\ F. 11,
Flu. 6.41 Effect of twisted pair 478
rl■ I 11
d
I
Ftc. 6.42 Paired cable relative to single power cable
Control and instrumentation cable systems he pair cable is a twisted pair then a reduction or of about 10 may be applied to this induced fact wItage as mentioned previously. Following through a similar logic for a pair cable in,lucing voltage on another pair cable of the same in Fig 6.43), we find a result which may ,..wometry (as as: athematically [s c stated m I
f
t
V =
4p.d 2 fI 2
2
(6.7)
(R - d )
Using:
2Adfl
V-
V/m
where d = 7 x 10 m R = 6 x 10 -1 m f = 50 Hz I = 840 A Thus V -
2 x 4r X 10 -7 X 7 x 10
-4
X 50 X 840
6x 10'
= 1.23 x 10 -4 V/m Allowing a reduction factor of 10 since the pair is twisted, Induced voltage = 12.3 AV/M Note: FIG. 6.43 One pair relative to another pair
V+ hat this means is that the induced voltage now drops off much more quickly as d is reduced and
also as R is increased. Note that in both Equations (6.6) and (6.7) a frequency term appears on the top li ne indicating that induced voltage is directly proportional to frequency. This is why transient phenomena (basically high frequency harmonics) may give rise to interference. If both the pair cables are twisted-pairs then a reduction factor of (10 x 10) may be applied. The type of interference that we have calculated here is manifested as a potential difference between the cores, i.e., a voltage source connected in series ith the cable. Thus this type of interference is known a, series mode voltage (or transverse mode voltage). It an be shown from the previous equations that both .ores will suffer a rise in potential above the local earth potential, again dependent upon the strength of the interfering field in which the cores are situated and this is known as common mode voltage (or longitudinal oltage). In general, the equipment at the end of the cable
d is calculated on the basis of a 1/0.8 mm diameter conductor with an insulation radial thickness of 0.3 mm
(b) A twisted pair suffering interference from (i) a single core, 25 mm away in the same cable and (ii), a twisted pair carrying balanced current also 25 mm away. In both cases the interfering conductor(s) is (are) carrying 1 A. (i) Using:
V
where d = 7 x 10 -4 m R = 2.5 x 10 -2 m f = 50 Hz I = I A Thus V -
:ables will now be given:
(a) A twisted pair suffering interference from a single
Power cable carrying 840 A, situated 600 mm away (effects of armour, other cables and supporting steel work are ignored).
2 x 4ir x 10 -7 x 7 x 10 -4 x 50 x 1 2.5 x 10
2
V = 3.5 x 10 -6 V/m
Allowing a reduction factor of 10 since one pair is twisted V = 0.35 AV/In
Ill
be examining the potential difference/current/ re,istance seen between the two cores and thus will he most sensitive to series mode interference. Common mode interference does not pose such a problem unless It is of very large magnitude, when special isolation methods must be employed. In this examination we are concerned mainly with series mode voltages. Two examples of interference calculations for paired ,
2fidf1
(ii) Using
V-
V=
4Ad 2 f1
R2 - d2
4 X 47 x 10
-7
(2.5 x 10
(7 x 10 -4 ) 2 x 50 x 1
X
-2 2
)
- (7 X 10 -4 ) 2
V = 1.9 x 10 -7 V/m
Allowing a reduction factor of 100 since both pairs are twisted: V = 0.0019 AV /m 479
41111111.1111mr..—___
Cabling
Chapter 6 (ii) represents an improvement of about 45 dB over (i), illustrating the importance of maintaining balanced pair working.
5.3.2 Interference in multicore cables The basic theory given in the previous section for multipair cables is equally relevant to rnulticore cables with the obvious exception that no factors have to be taken into account for twisting. Two examples of interference calculation will now be given: (a) Two adjacent cores suffering interferences from a single power cable carrying 840 A, situated 600 mm away (effects of armour, other cables and cable supporting steelwork are ignored). V=
Using:
20dfl
V/m
where d = 1.7 x 10 -3 m r = 6 x 10 -1 m f = 50 Hz I = 840 A Thus V
2 x 41- x 10 -7 x 1.7 x 10 -3 x 50 x 840 6 x 10 -1
V = 2.99 X 10 -4
Induced voltage = 299 ILV/M
Note: d is calculated on the basis of 7/0.67 mm stranded conductor with an insulation radial thickness of 0.7 mm. (b) Two widely spread cores within a 37-core cable suffering interference from a single power cable situated 600 mm away (effects of armour, other cables and cable supporting steelwork are ignored). Using:
V—
24fI
V/m
where d = 10.2 x 10 - 3 m R = 6 x 10 -1 m f = 50 Hz 1 = 840A Induced voltage = 1795 AV/M
Note: d is calculated for diametrically opposite cores in the outer layer of a 37-core cable, with conductor and insulation parameters as in the previous example. 5.3.3
Circuit considerations
From the previous sections it can be seen that multicore cables can be up to 150 times more susceptible 480
to interference than multipair cables under the con. ditions considered. The actual level of interference within multicore cables is dependent on the phys i cal location of the cores which are used to complete the electrical circuit. If the cores used are widely spaced within the cable, then the level of interference will b e greater than if adjacent cores were used. In general, little control is used over the selection of cores used and, in practice, cores forming an electrical circuit may even be in different cables in which case the levels of interference can be significantly greater. From Section 5.3.1 of this chapter, it can he seen that in order to reduce interference between circuits (cross-talk) and from external sources to a minimum, it is essential that balanced pair working is used. This means that the current in one core of a pair must be equal and opposite in direction of flow to that in the other core of the same pair. This is a mandatory re. quirement for analogue signals and should be adopted whenever possible for digital signals. Also from Section 5.3.1 it can be seen that inter. ference within a control cable is inversely pro portional to its distance from the source. Control cables are therefore separated from single-core power cables by at least 600 mm and from multicore power cables by at least 300 mm. Interference is directly proportional to the distance over which the control cable and power cables are parallel. It is therefore possible to waive these separation requirements over short distances and the requirement is not applied to cable ends where they are terminated into equipment. A general rule used is that power and control cables can be run at less than the foregoing stated separation distances provided that the summated total length does not exceed five metres. Analogue and digital signals are normally segregated into separate cables, but separation is not required between such cables. A further consideration when designing control cable systems should be the effects of cable capacitance. One particular aspect that needs attention is to ensure that the capacitance due to cable length or type is not such that the leakage current is sufficient to cause 'sealing in' of relay coils. Further information on the effects of capacitance is given in Volume F.
5.4 Control and instrumentation cable system design This section deals with the design of cable systems to handle circuits used for control, protection, instrumentation and communications within a power station. This design work is now generally carried out by the CEGB who also issue the detailed working instructions and drawings to the cable installer. The work involved on a major project such as Heysham 2 covers 36 000 control cables and well over 1 million wire terminations. Each 'cable' and each 'wire' has to be uniquely designed and identified to ensure
Control and instrumentation cable systems that the plant functions correctly. Because of the vast quantity of information involved, computer systems ow extensively used to aid design and to store are n
data. To understand the philosophy behind modern con1 system cable networks it is useful to consider first [10 how the extent of such systems has grown over the rs with increasing generator unit size. This evolution „a an be considered to have four phases. In phase one, prior to about 1950, auxiliary control Canctions within power stations were largely restricted the remote control of switchgear using voltages in the order of 110 V and currents that could be as high as 5 A. For these functions, multicore cables were used shich had an imperial sized conductor equivalent to 2 the modern metric 2.5 mm . All connections would be 'point to point', i.e., direct between equipment without arshalling of cores. A typical arrangement is shown m
in Fig 6.44,
CENTRAL CCNTROL PANEL
SWiTCHGEAR
LOCAL CONTROL PANEL
11
MOTOR CIRCUITS
PRESSURE SWITCH
;,..11•Cri
FIG. 6.44
PRESSURE TEMPERATURE SWITCH SENSOR
'Point to point' control cable system
During the second phase, in the 1950s, the increasing number of plant auxiliaries and level of instrumen!ation made it desirable to reduce the size of control panels for switchgear. The same period also saw the Introduction of mimic diagrams for control panels and desks. The equipment developed by the GPO for telecommunications was an obvious choice to reduce size and facilitate an increase in the complexity of power station control functions. The use of 50 V DC interPosing relays, and key and discrepancy switches theretore became common in power stations. The introduction of such equipment allowed the development
of sequence controllers and similar devices. The expression 'light current control' came into being and this was generally taken to mean devices operated via a 50 V system of relays and switches. It was realised that light current devices would operate satisfactorily through cables having a reduced cross-sectional area and that the introduction of 'telephone type' cables could result in considerable financial savings. Unfortunately, the importance of balanced paired working when using these types of cables was not always appreciated in early installations, and interference problems were sometimes encountered. To reduce termination space requirements, the traditional 0 BA terminals were replaced by screw clamp terminals, broadly in two sizes, one for multicore cables and a smaller version for multipair cables. The third phase was initiated by a further upsurge in quantity and complexity of control and instrumentation equipment in the 1960s with the introduction of 500 MW units, which put a heavy demand on cable systems. To achieve economy of cable cost consistent with the required reliability, operation and maintenance requirements a higher degree of marshalling was introduced. A typical arrangement is shown in Fig 6.45. With these marshalling systems, as with point to point cabling, all terminal points have to be individually designed and scheduled prior to site installation. Clearly the considerable amount of work involved cannot be completed until the necessary circuit and terminal information has been received from the various plant contractors. Because manufacturers programme plant contracts in relation to the equipment manufacture and delivery dates, the design information tended to be made available later than the cable system design task required. Consequently the cable design activity could not match the site cable installation demand for information. The resulting concentration of cable design and installation activity towards the end of the project was a threat to the construction programme. Although supporting steelwork could be erected and power cables installed, control and instrumentation cabling invariably was delayed due either to late information from contractors (and hence from the cable designers) or due to lack of terminal release points from the equipment contractors. A further difficulty with this type of marshalling system is that all wires had to be identified by a unique number at their terminal points to allow identification and for fault finding during commissioning and maintenance. This identification usually consisted of a nine-digit alphanumeric code formed using beads (ferrules) placed over the wire insulation. The termination was then completed by applying a crimped pin (see Section 9.3.1 of this chapter) to the conductor which would in turn be fastened into a screw clamp terminal. The larger sizes of paired cables (50, 75 and 100 pairs) used for trunk cables during this phase had a more complex colour coding than those currently used since all pairs were identified without repetition. The net result of 481
1•"' Cabling
Chapt er 6
CONTROL BLOCK
TRUNK CONTROL CABLES
MAIN MARSHALLING BOXES
FIRST MARSHALLING BOXES MAY BE DISPENSED WITH IF PLANT ITEM IS NOT TO BE CONNECTED TO MORE THAN ONE
PLANT iTEMS
TFILJNK CABLE:
FIG. 6.45 Typical arrangement of cable marshalling
these factors was that approximately 2 07o of wires were wrongly identified or terminated. The fourth and final phase of the evolution of the cable network system began with the introduction of 660 MW units in the early 1970s, which had associated with them more sophisticated control and data logging systems. There was clearly a need to review and if possible simplify the design and installation of control cables and terminations. It was also considered desirable to try and spread the load factor on the design and site labour forces. Such considerations brought about the adoption of cable networks which utilised jumpering facilities to complete the circuitry. This type of network has been used at stations such as Littlebrook D, Dinorwig and Heysham 2; a description of the principles and equipment used is given in the next section. 5.5 Cable network system using jumpering 5.5.1 Basic principles of cable network
The cable network is a hierarchical system formed to route circuits from the 'field' (plant areas, switchrooms, etc.) to the control room area. A simplified arrangement to demonstrate the basic principles is shown in Fig 6.46. As can be seen, the network is built up using 20-pair modules to match the type of multipair cables used. These multipair cables, which are fully described 482
in Section 3.6 of this chapter, are constructed on a unit basis. This means that each cable consists of a number of 20-pair units, the pairs of each unit having the same colour code identification sequence, the units themselves being identified by numbers. The network is built up in 20-pair modules from field marshalling boxes or local panels around the plant, via network marshalling boxes and trunk cables into a marshalling centre. Similarly, central equipment such as control desks or alarm equipment is connected in 20-pair modules via trunk cables into the marshalling centre. Therefore each 20-pair module will start in a field marshalling box or in an item of control and instrumentation equipment. All pairs of the field end of the module will be made-off onto terminals and the whole module will be extended back to the marshalling centre. Each 20-pair module is given a unique number that will appear above every block of 40 terminals that are used to terminate the module. Each wire in every module is terminated in the same terminal position in a block as shown in Fig 6.47. This means that a signal onto terminal 1A of, say, a field network box will end up on terminal 1A of the same module in the marshalling centre. Since each module is uniquely identified by a number and each pair within a module is uniquely identified by colour code, a system of attaching ferrule numbers to core terminations is not considered necessary. Since . the terminations within 20-pair modules should never need to be disturbed for correction or
Control and instrumentation cable systems
PIELO MARSHALLiNG BO%
L_
PtANT
20 PAIR CABLE
AC_ CABLE PAIRS TERMINATED IN THE SAME COLOUR
20 PAIR CABLE
PAM NETWORK MARSHALLING ROA
^CCE SEQuENCE TkR0u0NOuT
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JUMPER WIRES
MARSHALLING CENTRE
DESK
ALARM
CUBICLE
Flo. 6.46 Basic principles of pair networking arrangements
modification, wire wrap techniques as described in SQc[ ion 9.3.2 of this chapter are used. The marshalling centre itself consists of a termination cubicle or frame which is provided with jumpering
facilities. The function of the marshalling facility is to form into a circuit a number of loops that are brought in by pairs within the network. The circuits are formed bs means of jumpers installed between the ends of the multipair cables. Jumpers are terminated using tab Connectors, as described in Section 9.2 of this chapter, \Ouch provide the facility for breaking a circuit into ik fundamental pairs for testing. Each jumper has numbered ferrules applied at each end to enable it to be identified.
By way of an example of the use of this system, the signal from an oil pressure switch could be connected into a field marshalling box on terminals 4A and 4B. The signal would then appear on terminals 4A and 4B of the same module in the marshalling centre, which could then be jumpered to the appropriate terminals of the module routed to the alarm cubicle to initiate a 'lubricating oil pressure low' alarm. En a similar manner, jumper connections can he used to complete the circuit between the alarm cubicle and the alarm facia on the desk. This is shown in the form of a loop diagram in Fig 6.48. Connections into field marshalling boxes from plantmounted devices use screw/clamp terminations and 483
Cabling
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Fic. 6.47 Cable module terminations
ferrule numbers are applied to cable cores for identification. Indeed this policy is used for all terminations having less than 20-pairs to enable plant changes or disconnection for test purposes. This type of cable network system was developed to try and overcome some of the programme and technical difficulties, discussed in Section 5.4 of this chapter, that had been encountered with marshalling schemes that did not include jumpering. Let us consider how a network which includes jumpering can improve programme performance. It is expected that the backbone of the network system which includes field and pair network marshalling boxes, marshalling centres and associated trunk cables will be designed early. This is carried out before detailed circuit knowledge is available by using experience of previous station requirements and taking into account 484
any particular control function requirements. Control and instrumentation contractors are encouraged to forward at an early date their requirements for the number of outgoing pairs for their major panels, cubicles and desks to enable trunk cables to these items to be scheduled. When circuit diagrams are obtained from manufacturers for sequence, control and instrumentation, interlock and intertrip equipment, etc., the system loop diagrams can be prepared and the cable system completed. At this stage it is only required that the tail end cables from the field network boxes to the plant devices and the necessary jumpers be scheduled. It should therefore be appreciated that the design work has been spread over a greater period by being effectively started much earlier. Furthermore, the process is better able to cope with late receipt of information as well as design changes. Providing steps are taken
Control and instrumentation cable systems
CONTROL ROOM MARSHALLING CLIBICLE
FIE40
2 , TO
ALARM CUBICLE
CONTROL DESK
MODULE NUMBER
FIG. 6.48 Simplified loop diagram
io ensure timely civil access for trunk cables and marhalling centres, the site workload can also be started earlier and spread to give a more controlled, levelled and (hence) economical installation task. Because the large majority of terminations are completed in a repetitive colour code order they are less prone to error by the installer, thus reducing the problems that can occur at the commissioning stage. This repetitive type of termination encourages the widespread use of wire map terminations which are fast, reliable and more economic than the use of ferruled wires in screw clamp terminals. From a technical point of view, this type of network ss stem encourages paired working and hence improved ,iznal-to-noise ratio, as discussed in Section 5.3 of his chapter. Individual networks can be provided to meet segregation and separation requirements and this, together with computerised cable design methods, can i e the necessary quality assurance. 5.5.2 Switchgear and interlocking equipment No mention has so far been made of the involvement ot switchgear and hence the use of multicore cables in he network system. Switchgear at all voltage levels provides a large number of the inputs into a control and instrumen-
[ation scheme in the form of operations, indications
and alarms. In the past, equipment for interlocking and sequence control, and interposing relays for remote control have all been built into individual switchgear units, a unique specification being required for each panel. This obviously necessitated early finalisation of Control and instrumentation design in order that these
devices could be built into switchgear in the factory. This proved to be too inflexible from a programme Point of view. Late information from control and
instrumentation contractors, who were naturally dependent on mechanical plant designs, conflicted with the necessity to clear switchgear designs in time for delivery to site to meet commissioning dates. A ready solution to this problem is the use of standard switchgear control circuitry, so that no special equipment has to be housed in the switchgear enclosure other than the interposing relays. Having removed 'individual' control and instrumentation components from switchgear, it has to be located somewhere else and for this purpose an 'interlock cubicle' is provided. The cost, complexity and programme requirements discourages the purchase of a completely designed and factory-built 'interlock cubicle'. The solution is therefore to purchase a cubicle containing nothing initially other than terminal blocks, wiring and plug-in bases. This enables relays, timers, etc., to be plugged in as requirements become known. When designing the cabling from switchgear, certain circuits such as electrical protection (including VT and CT secondaries) are excluded from the cable network system. CT secondary circuits are excluded from the network because special measures, in the way of terminals with shorting links, are required to prevent the CT being left open-circuited when energised with resultant high potentials which may be a danger to personnel and equipment. However, circuits from interposing CTs may be routed via the cable network. These circuits therefore have their terminals grouped into discrete blocks to enable them to be cabled direct to their destinations using multicore cables. All remaining switchgear functions are wired to terminals in groups to match standard multicore cable sizes, i.e., 12, 19, 27 and 37 cores. From these terminal blocks, cables are run to identical terminal blocks in the marshalling cubicle and in this manner all the auxiliary functions of the switchgear are extended to 485
Cabling the jumper field. By means of jumper connections, functions can be extended to other equipment. Where extension is not required for a particular function, but circuit continuity is required (i.e., plant interlock in closing coil circuit), then a jumper is used as a shorting link. The 'module' approach, described in Section 5.5.1 of this chapter for paired cables, is also applied to muiticore cables. This means that core I is always connected to terminal 1, core 2 to terminal 2, etc., and this can form a standard instruction to the electrician. This technique can apply both to the switchgear and the marshalling centre, hence no wiring diagrams or connection schedules are necessary. All that is required is for the group of terminals to be identified by a module number and that this is then related to a cable number. Interlock cubicles are cabled direct to the marshalling centre, using multicore or rnultipair cables as appropriate, also employing 'module' techniques. 5.5.3 Design of cable network systems Section 5.5.1 of this chapter used a simplified model to
demonstrate the principles of a cable network system. In practice, the structure of the network will be dependent upon the segregation and separation requirements for a given project. These requirements are discussed in Section 2 of this chapter. This means that a separate segregated network will always be required for each unit. Segregation requirements will allow station services to be mixed with unit services provided that, in the event of any incident, not more than one unit and half of the station's services are affected. For example, one network could be provided for unit I and station A functions with a separate segregated network for unit 2 and station B functions. Whilst segregation is not required between station and unit services it is recommended that consideration be given to separation between marshalling facilities to reduce their size. This is because experience has shown that large marshalling centres can form an 'installation bottleneck' because access space limits the number of electricians that can work in a given area. For the same reason it is recommended that, on a conventional station, at least three marshalling centres are provided per unit. The location of marshalling centres is discussed later. However, a typical arrangement would be to provide such facilities at the control room, boiler electrical and turbine electrical annexes. A typical unit arrangement for a conventional power station is shown in Fig 6.49. For nuclear projects the unit electrical system may be provided on a 'train basis' (i.e., a separate electrical system associated with each reactor quadrant) and in this case it is necessary to have separate segregated control cable networks for each train. In addition each 'train' may comprise a number of 'sub-trains' (usually two), each requiring separation between cables 486
Chapt er 6 and marshalling centres. In this respect a sub-train i s the plant, equipment and cables associated with the essential cooling system. A typical arrangement for an advanced gas-cooled reactor (AGR) is given i n Fig 6.50. Regardless of the type of station, separate cables are used for analogue and digital signals although common marshalling centres may be used. A diagra m of a marshalling centre for an AGR showing typical jumpering is given in Fig 6.51. The location of marshalling centres is important. The initial reaction had been to set up a marshalling centre only adjacent to the control room, an evolution of the earlier idea of using small trunk cables as shown in Fig 6.45. However, as the control cable network has developed to accommodate all C and I circuitry, the physical location of marshalling facilities has had ro be closely re-examined. The actual position will der. j on the specific station layout and therefore no h .rd and fast rules can be applied, but when considering this subject the following points should be taken into account: • In order to reduce the length of multicore cables between switchgear and the marshalling centre, which are relatively expensive as compared with multipair cables, a marshalling centre should be located as close as practicable to the switchgear. • For the same reasons as given above, the interlock cubicles should be positioned near to a marsha: centre. • A marshalling centre should be provided in control block. This should he located as do possible to the underside of the desk to allo flexible cables from individual desk modules terminated directly into the marshalling centre • Where switchboards are located in outbuildings a s mall marshalling centre should be provided, i.e., wall-mounted jumpering boxes. 5.5.4 Application of cable network systems
As soon as the locations of the major items of plant (mechanical, electrical, and control and instrumentation) are known, the trunk cabling of the cable network system should be laid out. This requires that the marshalling centres are located and that an estimate is made of the number of analogue and digital pairs that are required between major plant areas. This is achieved by using experience of previous station requirements and a knowledge of any particular control and data requirements for the station. When estimates for the trunk routes have been prepared, the number of pairs should be increased by 20% to allow spare pairs for modifications and additions during construction and to achieve 10 0/o spare pairs for future modifications and extensions. It Is considered preferable to provide adequate spare ca-
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151
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Control and instrumentation cable systems
II1
Cabling pacity at this stage since the cost of pairs in large trunk cables is only 10 67o of that of small individual cables that might otherwise have to be added at a later stage. Having established the trunk cabling, the remainder of the network has to be designed on an individual circuit basis. This can only be done when the location of individual plant items becomes known. To this end, plant manufacturers are encouraged to forward their requirements at an early date so that the location of control panels and the requirements for field marshalling boxes can be assessed. The number of pairs assessed in this manner should then be rounded up to the nearest multiple of 20-pair modules to assess termination and cabling requirements. The next stage is to obtain circuit diagrams from manufacturers for sequence, control and instrumentation, interlock equipment and the like. This information, together with standard switchgear diagrams, allows system circuit diagrams in the form of loops to be prepared. These are produced on a system basis to enable the information to be allied directly to design, erection and commissioning. At this stage it is expedient and efficient to use a computer management program (e.g., the CEGB CADMEC program) to allocate cores in cables and to produce termination schedules. The CADMEC program may be used to: • Allocate the cores/pairs of cables required to route each circuit element of the system circuit, and to
produce printouts displaying all routing details. The circuit elements will be routed as balanced pairs and displayed as such where the circuit element references (CER) are assigned to pairs of terminals at equipment. Note:
A circuit element comprises the electrical connections identified by the same unique circuit element reference (CER) between circuit components (contacts, relays, etc.).
• Produce marshalling centre jumper schedules. • Produce a schedule of connections for the field multipair and multicore marshalling boxes. • Produce the circuit loop information in schedule form. The 2, 5 and 10-pair, or multicore cables to plantmounted devices at the extremities of the network also have to be scheduled during this stage. It should be appreciated that the amount of information necessary to install and terminate cables is minimal, as the only unique connections required are for the jumpers in the marshalling centres and for the field cables connected into the field network marshalling boxes. The information provided by the computer system is in a form that can be issued direct to the installation contractor's labour. It is standard practice 490
Chapte.
to provide a computer terminal on site to enable cable requested a s required.
and termination information to be
5.5.5 Testing and commissioning of a control network system
After installation of the network cable system and prior to jumpering, the paired section of the netwo r k should be tested to ensure: • All cores are clear of each other and earth. • Continuity of conductors and termination through the network.
• Correct allocation of terminals, i.e., terminal IA at one end of the cable is connected to terminal IA at the remote end. Automatic test equipment is available to carry out these tests. The tests are normally carried out using the master test equipment at marshalling centres and a slave unit at the extremity of the network, e.g., field marshalling box or panel. In this way intermediate terminations such as those at pair network marshalling boxes are also verified. The correctness of connections from field equipment into field marshalling boxes, and of jumper connections as well as multicore sections of the network, is verified by pre-commissioning checks. 5.5.6 Plant-mounted devices
It is considered good practice to connect plant-mounted devices such as pressure switches, transmitters and resistance thermometers via a flexible cable into an adaptable box. This adaptable box then forms an interface between the device and the permanent armoured cable. The flexible cables for general use are PVC insulated with a copper braid screen and PVC outer sheath complying with DEF Standard 61-12 Part 5. For special high temperature applications, in the range of 70 ° C up to 250 ° C, PTFE insulated and sheathed cables may be used. These types of plant-mounted devices are normally supplied under plant contracts and it is preferable that they be supplied complete with at least I m of flexible cable. The adaptable box should be supplied and erected, and the flexible cable should be cleated and terminated by the cabling contractor. The advantages of this method of connections are: • Devices can be removed for recalibration without disturbing the armoured cables. • Many devices are mounted on pipes and the undesirable effects of vibration and movement on conventional cabling are avoided. • High temperature flexible cables may be used to devices located in conditions which would not be suitable for the permanent armoured cables.
Control and instrumentation cable systems
•
The cable contractor is free to install and termihe permanent armoured cable prior to the nate t do ice being installed and released to him. It should he borne in mind that it is not unusual for plant ontractors to install devices at the last possible ,i moment, to avoid damage.
rhe problem that many devices do not have suitable • cntries for armoured cables is overcome.
to the boiler burner panel and/or to the individual burners dependent on the boiler control scheme containing the boiler firing trip circuit. (b) The cables from the unit overall protection panel to the individual stop valves containing the valve trip circuits. (c) One of the two cables from the unit overall protec-
follows: Thermocouples are cabled using compensating cable • direct to their associated cold junction cubicle or transmitter cubicle. Frequently the supply, installacion and termination of compensating cables i s placed in plant contracts.
(d) The cable from the unit overall protection panel to the unit transformer circuit-breaker containing the trip circuit.
• Plant devices mounted on the turbine and boiler feed pump turbine blocks are grouped and cabled into marshalling boxes. The location of the marshalling hoi(es must be such that they need not be disturbed during dismantling of the turbine and that they are accessible with the unit on load. It is recommended ihat flexible cables and adapter boxes still be used for plant devices, but in this case all cabling and equipment up to and including the turbine marhalling boxes should be supplied by the plant contractor. Connections from these marshalling boxes io network marshalling boxes or marshalling centres .hould be the responsibility of the cable contractor. 5.51 Application of short - ti me fireproof cables HI,:
separation and segregation requirements given Section 2 of this chapter are intended to minimise risk, limit consequential damage and eliminate :; Hilti-tinit outage without extensive use of fire survival —ibles. However, there are situations where if cables led due to fire it might be impossible to shut down .1 unit safely and isolate it from the Grid System. ise, there is certain equipment whose integrity intist be maintained to enable evacuation and fireng to be effective. Such equipment must be cabled short-time fireproof cables (STEP) of the type Jc\cribed in Section 3.7 of this chapter. Because of the nsiderable cost of STFP cables, their blanket use ,n oicry alarm and protection circuit is not considered i :eptable. It is considered appropriate to use STFP abIes for the following applications. )
,
(a) The cable from the unit overall protection panel
production of individual wiring diagrams oid the i 0 deach device, standard connections are used as shown i Fig 6.52. This diagram forms part of the standard Fig 6.52. issued to electricians for use on site. There are a few areas where plant devices need to treated in a different manner and these are detailed
• Where short-time fireproof cables are used (see Section 5.5.7 of this chapter), a higher degree of security is achieved by terminating the cable direct Into equipment and devices.
,
Main plant protection (see Fig 6.53)
tion panel for the duplicated intertripping scheme to the 400 kV switchgear protection panel in the 400 kV substation. If it is possible to route the two cables by segregated routes it will not be necessary to use STFP cables.
(e) The cable from the unit overall protection panel to the field circuit-breaker (when provided) containing the trip circuit. (f) The cable between the unit control desk and the unit overall protection panel containing the emergency stop pushbutton circuitry. (g) To overcome the possibility that the fire could involve the generator stator circuitry, it is necessary to ensure that some form of electrical protection should survive. The form of protection involving the minimum of cable is the back-up earth fault protection on the stator, consequently it is a requirement that the current transformer secondaries of this protection scheme be cabled to the unit overall protection panel in STFP cable. Station public address system
The complete cabling system from microphones to loudspeakers via amplifiers and switching should be in STFP cable. Audible alarms
Power feeds for alarm bells arid sirens are usually
provided from several local sources on the basis that the loss of one device through lack of supply will not silence the alarms. Where it is considered that the loss of any one device is not acceptable (and considering the need to cater for maintenance outage this is unlikely), then the power supply to the device should be in STFP cable. There is, however, a common signal cable from the control room to initiate the local bell/ siren contactors and the loss of this cable would produce a complete failure. It is essential, therefore, that this cable be installed in STFP cable. 491
Chapt er 6
Cabling
RESISTANCE THERMOMETERS
.1 PRESSURE SWITCHES ETC F
--K
-
1 1
-L--I
NO
ADAPTABLE Box
ADAPTABLE BOX
OE-1C6
2
1
L ,
a
. 1 3
t
I
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.,,__. „...__ _
'
1
.
3
;.
/
CORE NLMBER CODE N.
-
H :
2
: 'I
Al
WHITE
C
- I • oPANGE •
4
ADAPTABLE BOX
DEVICE
,
BLUE
2
RED ORANGE
3
\
RED
PAIRED CABLE
CORE NUMBER CODE
PAIR COLOUR CODE
Box
'
LtuL TiCORE CABLE
\ PA:REO CABLE
ADAPTABLE
■-!
A
O.2PE DEW IF CATION MAJ=11
DEVICE
BLUE
2
: RED • 1 ..„,..) ORANGE
--------
HIT
BLUE
■
— 2 L-1—
-
._.,
.LEX,BLE :ABLE
1 c-, WHITE
-- -1 171- i ;
-:
•,41
1 -
3
1-11 -1" ="171 -1 4
A
PAIRED CABLE TERMINALS
2
MULTICORE CABLE
;1 ORANGE '• CABLE
FLEXIBLE CABLE
PAIRED
ADAPTABLE BOX
N O
•
-1
CABLE CONNECTIONS AS 1 1:.} 3
3 TRANSMITTERS
ADAPTABLE BOX
TRANSMITTER I
:
TERMINALS 2 AND 3 LINKED
1-{ I-4-1
BLUE
2
WHITE 3
ORANGE 5 1-n1 -
f
I
7 -n
a —I
WHITE GREEN WHITE BROWN WHITE
I S
H
GREY 5 PAIR CABLE
Flo. 6.52 Standard connections to plant-mounted devices
,
UE
.3 h I
4
i RED
. -
WHITE
WHITE
1
2
FLEXIBLE CABLE
ADAPTABLE BOX
492
I 2
7
i •-,
1
1
1 ORANGE
.
,
PAIRED CABLE
Control and instrumentation cable systems
1
LOCAL I' uSSINE TRIP LEVER OVERSPEEG I- RIP
LOSS OF LLBRicAT,NG OIL
AN
TURBINE STEAM VALVES
RELAY FLUID PRESSuRE SWITCH
VACUUM TRIP
.3. 0 ,._Eg
ELEC SOLENOID ON TURBINE TO RELEASE FLUID AND TRIP TS VS
LOW STEAM ,NLET PRESSURE
TURBINE
LOSS OF SPEED GOVERNOR TRIP
\-
BOILER FIRING TRIP
-16
1< .1
1 LOSS OF BOILER WATER
\
NH EMERGENCY PUSHBUTTON REMOTE 8 LOCAL
_ OVERALL PROTECTION BUCHHOLZ SURGE
_NI T TRANSFORM ER
■
\\— HV OVERCURRENT -
LV BALANCE EARTH FAULT
"\— LV STANDBY EARTH FAULT
LOSS OF GENERATOR EXCITATION A
LOSS OF STATOR WATER FLOW GEN
STATOR EF (INSTANTANEOUS HIGH RESIST)
0 0 L
GEN STATOR STANDBY ET (INVERSE HIGH RESIST)
GENERATOR
NEGATIVE PHASE SEQUENCE GEN STATOR B/F (INSTANTANEOUS LOW RESIST) GEN STATOR STANDBY EF (INVERSE LOW RESIST)
• WINDING TEMPERATURE • OVERALL PROTECTION
ELECTRICAL SIGNAL
BUCHHOLZ SURGE MECHANICAL/HYDRAULIC SIGNAL • Hv OvEACURRENT GENERATOR TRANSFORMER AND 1W CO NNECTIONS
\
Nu _
HV BALANCE EARTH FAULT FIRST MAIN FEEDER PROTECTION SECOND MAIN FEEDER PROTECTION INTERLOCKED OVERCURRENT *
A
PERMISSIVE INTERLOCK DEVICE CONTACT WHICH CLOSES ON OPERATION OF SENSITIVE POWER RELAY FOR DETECTING CUTOFF OF STEAM SUPPLY TO TURBINE
INTERLOCKED OVERCURRENT NOT REQUIRED IF MI/ BUSBAR PROTECTION TRIPS UNIT
NY BUSBAR PROTECTION SHORT TIME FIRE PROOF CIRCUIT
FIG. 6.53 Application of short-time fireproof cables for main plant protection
493
Cabling Station VHF and UHF links All cables from the microphones at the unit control deks out to the transmitters covering the various areas of the station should be in STFP cable. The aerial cable from the transmitter is co-axial and is not available in a fireproof construction it must therefore be routed in a low risk area. Direct wire telephones Direct wire telephone circuits are routed point-to-point using STFP cables. Fire fighting equipment In order that diesel pumps and other mechanical plant necessary for the continuous operation of the fire fighting equipment shall remain in service when involved in a fire, any cabling on that plant or required to start it in case of fire should be in STFP cable. Likewise, circuits carrying essential alarms from the fire fighting equipment to the control room should be in STFP cable. Fire detectors Fire alarm initiating devices, e.g., 'break glass' devices, smoke detectors and heat detecting cables should be cabled in STFP cable only in the areas that they are protecting. Outside these areas, the circuits should be routed in the multipair cable network. This is on the basis that the alarm circuits are all self-monitoring. Nuclear alarms All detector and audible circuits associated with nuclear alarms should be cabled using STFP cables only. 6 Cable support systems
6.1 Introduction In modern power stations, large quantities of steel framework type structures are used to support the cables on their paths, both horizontally and vertically, across the power station. In the horizontal case, these cables may be routed in purpose built cable tunnels, in cable 'flats' or in general plant areas. In the vertical case, the cables may be running in purpose built 'risers' (sometimes referred to as cable 'flumes'), or si mply through slots in floors/ceilings, again in plant areas. Virtually all of the cables used in a power station, both power and control, will be installed on these steel support structures for at least part of their length. In addition, the following installation methods are also used for some cables: • Buried direct in the ground. • Installed in ducts. 494
Chapter 6 • Routed in concrete troughs. These three methods, by their very nature, tend to be used outside the main station buildings; they are dealt with in more detail in Section 7.5 of this chapter. Additionally, a very small number of cables will be installed either in proprietary electrical trunking or conduit. This applies chiefly to lighting and small po wer circuits such as socket outlet ring mains. Cables for such circuits will be installed in accordance with the edition of the IEE Wiring Regulations [18] valid at the time of installation. The result will therefore be si milar to any other industrial electrical installation. Further consideration to such circuits is not, therefore, given here.
6.2 Design philosophy A generic design of cable support steelwork has been employed by the CEGB in all of its most recent power stations. The main considerations in arriving at this design were as follows: • The diversity of locations across a power station where cables, and hence their support steelwork, are installed. At one extreme, these may be purpose built cabling areas such as cable flats, at the other they may be plant areas such as the boiler house or turbine hall. • The huge differences in quantities of cables which need to be installed in these differing physical locations. Main cable routes like cable tunnels may carry as many as 1500 cables, whereas 'tail end' routes may simply consist of two cables (one power and one control) being routed to, for example, a li mit switch. • The considerable variation in cable sizes and weights which need to be accommodated. At one extreme, a 4-core 300 mm 2 power cable has an overall diameter of around 70 mm and weighs 7 kg/m. At the other, a 2-pair multipair control cable has an overall diameter of 12 mm and weighs only 0.3 kg/m. • The need for the support steelwork to accommodate the installation requirements of different cable types. Power cables, for example, require a free flow of air for cooling purposes and single-core power cables need additionally to be firmly anchored to restrain the large bursting forces generated under fault conditions. (These requirements are addressed later in this section.) Clearly it was considered an uneconomic proposition, both in terms of design and manufacture, to use cable support assemblies unique to each different application and therefore the idea of using a large 'construction kit' evolved as the means of providing the most flexible solution.
Cable support systems ----The basic components of this construction kit were by the CEGB throughout the 1970s in develop ed collaboration with the leading UK manufacturers. The design which resulted from this work drew on both the EGB's installation experience and also the suppliers' c practical manufacturing experience. The culmination f this development exercise was the production of o n internal CEGB specification known as GDCD a Standard 197, [19]. This document has, in the absence specifications from national sources, become the of epted standard for this type of cable support system acc throughout the UK. This design of steelwork has been ed with considerable success on all of the CEGB's us recently constructed power stations including Drax Completion, Heysham 2, Dinorwig and Littlebrook D. 6.3 Basic system components The cable support system employed by the CEGB is based upon a proprietary design of 'open channel' teel section, manufactured in a common format by a number of UK companies. Indeed, the same basic format of channel is readily available worldwide. This basic channel section, referred to in CEGB documentation as a Cl channel, is in the form of a square, open on one side, 41 mm wide x 41 mm deep, rolled from 2. 5 mm thick steel. A cross-section through this channel is shown in Fig 6.54. There are three other basic channel sections employed by the CEGB which are v ariations on this theme, these are:
TWO LENGTHS OF C „HANNEL WELDED SACK 7C SACK
Etc. 6.55 Cross-section through a C2 channel
22 2mm
20 Emm
41 2mm
Fin. 6.56 Cross-section through a C3 channel
41.2mm
Fin. 6,54 Cross-section through a Cl channel
• A C2 channel, formed from two Cl channels placed
back - to - back and spot welded at 150 mm intervals (see Fig 6.55).
• A C3 channel, which has a depth of only 21 mm, i.e., half that of the basic Cl channel (see Fig 6.56).
• A C4 channel, which is similar to a Cl channel except that tangs are pressed out from the rear face of the channel at 300 mm intervals (see Fig 6.57). This type of channel is called a 'concrete insert channel' and is used to provide a convenient means of fixing cable support steelwork to the power station civil structure. The channel is temporarily fastened to
PLASTIC FOAM NOTE: THE MAIN CHANNEL SECTION UTILISES THE Cl CHANNEL SECTION THE INSERT TANGS SHOWN ON THIS DRAWING ARE TYPICAL ONLY
FIG. 6.57 Isometric view of a C4 channel
the inside surface of the shuttering prior to concrete pour, special polystyrene inserts being used to prevent ingress of concrete into the channel itself. The result is an open channel fixing point, flush with 495
Chapt er 6
Cabling the concrete wall or ceiling. The tangs in the rear of the channel will be embedded firmly in the concrete. This type of concrete insert channel provides a very cheap method of providing fixings to the civil structure but it does have its drawbacks. These are discussed in greater detail later in this chapter. These basic channel sections are used in conjunction with a range of standard bracket formations and fixings to form a support framework on which the cable carriers are located. The brackets and channels are connected together using special fixings known as sprung channel nuts (sometimes referred to as `zebedees'), and standard hexagonal head set screws (usually M12) of grade 8.8 steel (as defined in BS3692 [20]). The design of the sprung channel nut is illustrated in Fig 6.58 and the basic composite assembly is shown in Fig 6.59.
Fio. 6.58 Isometric view of sprung channel nut
BRACKET
CHANNEL
FIG.
6.59 Channel nut/screw assembly in a Cl channel
The main advantage which this type of connection has, is that the support frameworks can be erected at site without the need for drilling, giving major savings in assembly time and manpower requirements. The channel nuts are simply inserted sideways into the channel between the lips on the open face, depressed, and twisted into place. The spring holds the channel nut in place whilst the assembly is being effected, hence freeing the operative's hands for other assembly jobs. This means that a reliable connection can be made very quickly and that a great degree of 496
installation flexibility is obtained, since a conne .ctio n can be made at any point on a channel. These reductions in assembly time and the m an . power needed, produce considerable consequential installation cost savings. It is worth noting that a version of the basic channel nut is also available without the spring. It is necessary to use this type of nut in conjunction with the C3 channel as the limited depth prevents the use of the spring. Because no drilling is required to form this type of connection, it follows that for loads parallel to th e major axis of the support channel, the basic load. carryingcapacity of the connection is being derived from a friction grip. To ensure adequate performance of this frictional grip, the top surface of the chann e l nuts have specially serrated grooves milled into These grooves, which can be seen in Fig 6.58, are 0. matically aligned with the inturned lips on the si.:pport channel and consequently, when the fixing screw is tightened, these bite into the underside of the channel lip. This creates a very high-strength friction grip. The actual load-carrying capacity of the connection parallel to the channel major axis will therefore be directly dependent upon the tightening torque applied to the fixing screws. For grade 8.8 M12 fixings, the CEGB specifies that a torque of 65 Nm be applied and this gives a slip resistance capability of typically 2700 kgf. For cable steelwork design purposes, however, the maximum permissible static load on a fixing is taken to be 1200 kgf allowing for a factor of ,,afety. One design of channel section which is widek ailable in the UK, actually takes this type of con. :ion further by having a sawtooth formation on the Jerside of the lips. This mates with a similar for .:tion on the top surface of the channel. In this type of connection, a high tightening torque is not so critical in obtaining the required load-bearing performance, as the interlocking teeth provide the resistance to movement. This design of steelwork is, of course, more expensive than the plain type. Since the required level of performance can be obtained without the need for a channel lip sawtooth formation, the CEGB does not feel it necessary to require this feature in its specification document. The standard types of brackets which are used in the construction of the support frames have been chosen to be simple and hence cheap. The bulk of the bracket designs are simply bent from 6 mm thick plate with holes punched in them to accept the fixing screws. Typical examples of these brackets are illustrated in Fig 6.60. They are all manufacturers? standard catalogue items. Welding will only be employed in the construction of the bracket if it is: • Essential to form the required shape of bracket. • If it is necessary to add strength to the bracket, for example the addition of a gusset to add strength, as illustrated in Fig 6.61.
FIG. 3.11 Large core being bulk (GEC Aisihon)
(luoiriSIV J:19) sliori
5ts!motic `aicr• pPlarchuoa
Z.1
FIG. 3.58 Core and windings of single-phase CEGB generator t r ansformer (GEC Alsthom)
1111111111 111 W111111111111111 1111 111111111 H[111111111111111 1111 111111111
V
VA:. 3.60 800 MVA gerwr.mor transrormer bank at Drax power
NiailOn ((iIL( ' Aki1/011/)
Flo. 3.64 Cast-resin transformers for Mstallation M 41.S V switchgear (GE(' Alsitiom)
FIG.
5.11 Two poles (of a three-phase group) of a forced-air cooled generator circuit-breaker installed at Dinorwig pumped-storage pov6er station (British Brown-Boveri Ltd)
5.12 One pole of a forced-air cooled generator circuit-breaker, with side covers and the connection to generator busbar removed (British Brown-Boveri Ltd)
FIG. 5.13 Three-phase water cooled generator circuit-breaker showing connection into the generator phase-isolated busbar system (British Brown-Boveri Ltd)
Ftu. 5.4 Generator circuit-breaker control panel (British Brown-Boveri Ltd)
5.3-=
Fio. 5.15 Cooling water plant (British Brown-Boveri Ltd)
Ikk'
. .
.-
FIG. 5.18 Air plant control panel (British Brown-Boveri Ltd)
Fic:. 5.29 Typical 3.3 kV switchboard of Rcyrolle manufacture
Ftc. 5.48 3.3 kV switchboard of Reyolle manufacture. The three left hand units are 'fused equipment Class S14A' and the three right hand units are 'air circuit-breakers Class SA'.
Fai_ 5_51 Typical 415 V swilchboare of lilcciro-Mcchaoical Maoulacioring Co inanolatiurc
PLC, 5.69 Switchboard formation of control gear featuring vacuum interrupters in association with !IBC fuse protection for 3.3 kV (GEC Industrial Controls Ltd)
st.111 iCe
Fin. 5.70 Example of control gear featuring vacuum interrupters in association with fiBC fuse protection — for 3.3 kV service, showing the 'demonstration of the circuit earthing switch (GEC Industrial Controls Ltd)
Cable support systems (i.e., prior to mass concrete pour). This information is generally available for major dedicated cabling areas such as tunnels and flumes where it is possible to predict the quantities of cabling, and hence support steelwork, required in those areas. Such detail design information is not, however, available for the many smaller cable runs, particularly in plant areas where plant layout, and its associated fixings, will still be subject to change. The use of concrete insert channels does, therefore, have its limitations. It is also worth noting that the CEGB has experienced practical problems where concrete insert channels have become misaligned during concrete pouring. This is attributed to insufficient care being taken when fixing these channels to the shuttering. It is therefore a quality control problem which
Ito. 6.60 Typical examples or brackets without welded components
FIG. 6.61
can be addressed by more rigorous on-site inspection. The most straightforward alternative to using concrete insert channels is to 'surface mount' lengths of Cl channel using wrap-around brackets and proprietary concrete fixing anchors (expansion or cast resin types) as shown in Fig 6.62. In this arrangement, a fixing anchor spacing of I m is usually deemed to provide equivalent load-carrying capabilities to concrete insert channels although this will, of course, depend upon the performance characteristics of the concrete anchors used, the strength of the concrete itself (which also affects the performance of the concrete inserts) and also the proximity of those fixing anchors to discontinuities in the wall or floor. These aspects are addressed by the manufacturer's instructions provided with the concrete anchors themselves, and these instructions must always be followed implicitly.
Typical example of bracket with welded gusset
!Arnim DPA HOLE
Cl CHANNEL
111 brackets are hot-dip galvanised after fabrication ro provide environmental protection. Post-fabrication Hot-dip galvanising is specified for two reasons: • The inclusion of zinc in a weld (from galvanising) will significantly weaken that weld.
Wilf
ittmcvm
• Bending and forming after galvanising can cause Flaking of the galvanising to occur. Ihe CEG13's standard component range also includes
a number of brackets and fixings which are used for xtaching the steel frameworks to the civil structure. dn this context, the civil structure will include not only load-bearing walls, floors and ceilings but also tructural steelwork such as columns and rolled steel mists (RSJs).) The basic type of civil structure fixing method, the C4 concrete insert channel, has already been introduced and described. Whilst this is a very simple and Lnexpensive method of obtaining a fixing point from a structural wall or ceiling, its use relies upon quite detailed cable installation design information being available at an early stage in the power station construction ,
1/411 2 CONCRETE ANCHOR
CHANNEL BRACKET
FR,. 6.62 Surface-mounted Cl channel using a
single
fixing anchor per fixing point
The surface mounting of Cl channels is more expensive than using concrete inserts for the following reasons: • It requires additional components, most notably the concrete anchors themselves, which are quite expensive. 497
Cabling
Chapter 6
• The increased installation time and effort resulting from the need to drill both the channel and also the concrete itself. (The need to drill the mounting channel can be avoided by using brackets which wrap around that channel, see Fig 6.63. This will of course, require two concrete anchors per fixing point rather than one.)
1.1(,. 6.64 Basepiate !or a CI channel
FIG. 6.65 Baseplate for a C2 channel
FIG. 6.63 Surface-mounted Cl channel using two
anchors per fixing point
Care should always be taken when drilling structural concrete walls or ceilings to ensure that reinforcing bars are not damaged. In addition to using lengths of channel to provide fixing points on the civil structure, the CEGB's standard also includes a number of floor/ceiling baseplate brackets. The two basic designs of these baseplates are shown in Figs 6.64 and 6.65 which are intended for use with Cl and C2 channels respectively. These baseplates are fixed to the floor or ceiling using proprietary concrete anchors and the upstands provide the take-offs for the channels. Again, they are designed to be very simple and hence inexpensive, with environmental protection being provided by hot-dip galvanising. For the more elaborate cable steelwork assemblies, which are described in the next subsection, special designs of floorplate are provided in the standard range of components. These have a wide variety of upstand configurations which combine installational flexibility with stable load bearing capacity. They remain, however, more specialised forms of the basic brackets shown in Figs 6.64 and 6.65. 498
Many physical situations on a power station dictate the need for cables to be routed to plant which is remote from concrete walls or ceilings. In these cases, the structural steelwork is often used to provide fixing points for the cable steelwork. A specially designed beam clamp, known as a BI5 clamp (see Fig 6.66), is used for this application which provides a convenient method of fixing from the flange of a RSJ. The beam clamps are used in pairs in conjunction with
FIG. 6.66 A B15 heavy duty beam clamp
Cable support systems lengths of CI or C2 channel. The completed ,hi.semblv, o rt shown in Fig 6.67, has a load-bearing can,ibilitv of 1200 kg which makes it suitable for the or complete cable steelwork assemblies. it er, also used to provide upper bracing points .,ieekork structures fixed to the floor. ror
6.69 Application of cladding rail hook bolts
UK, 6.67 Application of a B15 beam clamp
Two other standard components are also used to provide fixings from structural steelwork where smaller load - carrying capacities are required or simply if a bracing point is being provided. The first of these is a duty beam clamp which again provides a fixing from the flange of a RSJ. This type of bracket, shown Fig 6.68, is usually used to provide a bracing point for the box section bridges described in the next sube,:tion. The second is a hook bolt fixing which is to gain a cable steelwork fixing point from ..iaLlding rails, The application of this type of fixing is shown in Fig 6.69. ,
When fixing cable steelwork to the structural steelwork, it is obviously very important to check that the structural steelwork itself is capable of supporting the intended cabling loads safely (bearing in mind that it may also be carrying other equipment loads such as pipework). It is therefore essential to ensure that co-operation and co-ordination exists between the civil and electrical design disciplines when determining cable supporting steelwork routes. The same civil structure loading considerations must also be observed when providing fixings from concrete walls and floors, although the civil design often includes an allowance for loads such as these. The other large group of components which make up the complete system are the cable carriers. Since the bulk of cable routes in a power station are horizontal, the most commonly used cable carriers are those which support the cables along these horizontal routes. The cables are supported on so-called 'ladder racks' which are formed by welding sections of standard C3 channel together. Essentially, the ladder rack consists of two C3 side rails joined by C3 channel 'rungs' at 300 mm intervals as illustrated in Fig 6.70. Three standard widths of ladder rack are available, 600 mm, 450 mm and 300 mm, their use depending on the quantity of cables to be carried. This basic format of cable carrier was selected because it was seen to offer the following advantages: • The ladders offer a flat surface on which to lay the cables. This permits them to leave and join the ladder without having to negotiate obstacles such as upturned lips. • The open channel ladder rungs and side rails provide convenient points at which to cleat the cables.
Fit,. 6.68 A light duty beam clamp
• When compared with other cable carrier types, such as perforated trays, ladder racks offer high strength with low self-weight. A given design of support frame can therefore carry a higher cable weight. 499
Cabling
Chapt er 6
CONSTRUCTED FRom C3 CHANNEL SECTION LADDER ASSEMBLED WITH ALTERNATE AuNGS WEB UPPERMOST REF I WIDTH ,Armn., TOO '
-1 50
L3
.
500
FIG. 6.70 Ladder rack
• The ladder type format allows free access of air to the cable hence providing cooling by natural circulation. Cable ratings will therefore be higher when using this type of carrier. • The ladder racks are completely compatible with the support steelwork and, since they are made from standard channel, can be supplied by the same manufacturer as the 'construction kit'. A small cost is paid for the above advantages in that the ladder type carriers are slightly more expensive than their perforated tray counterparts. This is chiefly due to the welded content of the ladders which, for the majority of manufacturers, is still done manually. Attempts have been made to introduce automatic welding processes with varying degrees of success but automation will, in the long run, reduce costs. The ladders are fabricated in standard six metre lengths, protection being provided by hot-dip galvanising after fabrication. The ladders are constructed such that alternate rungs face upwards. The upward facing rungs provide cleating points for the cables, whilst the downward facing rungs provide the facilities for the installation of linear heat detecting cable (see Section 8 of this chapter for more detail). Great care is exercised during fabrication to ensure that the tops of the rungs are level with the tops of the side rails. This is important since any mismatch could leave burrs or weld-bead protrusions which could damage cable sheaths. Similarly, care is taken to ensure that any galvanising 'spikes' are removed by fettling immediately after the racks are removed from the galvanising baths. The standard sizes of ladder rack which have been chosen are derived from a 'modular' basis for deter500
mining cable weight-carrying capacity. The modular concept stems from the computer-aided cable routing program which the CEGB employs in managing cable installation contracts (see Section 14 of this chapter), A module consists of a 75 mm x 75 mm area of available ladder space (75 mm of support width x 75 mm of support depth). The GDCD Standard 197 steelwork is designed to be capable of supporting a cable loading of 7 kg/module/metre run of support. Therefore, a 600 mm wide ladder rack, the largest of the standard rack widths, when allowing for the nonusable space at the side rails, is capable of accommodating seven modules worth of cables, or, 50 kg/m rounding up. For a 450 mm wide ladder rack, the corresponding figure is 35 kg/m and for a 300 mm rack, it is 20 kg/m. These loading figures give the maximum permissible cable loading for the given ladder size on a module by module basis. In practice, the cable cleating philosophy used by the CEGB (see next section for details) may mean that the ladder rack is physically full before the maximum permissible total cable load has been reached. Another factor which plays a big part in determining the total cable load on a rack is the total combustible mass, comprising the cable insulation and sheathing materials. This is important from a fire propagation point of view. The maximum permissible combustible mass loading on a cable ladder is again expressed as a weight per metre run of carrier and the limiting value will vary dependent upon cable type, cable size, insulation material and installation method. When the automatic cable routing program has allocated cables to carriers it therefore checks three items: • Combustible mass loading.
Cable support systems • T o tal weight loading. • Phsical space available to suit prescribed cleating i
neihods.
i :c
„:11ecks are hierarchical, being performed in the o rder.
rilportant to note that the construction of all of ladder rack is the same, save for the rung ,iteS Therefore, the actual load carrying capacity of three sizes will be the same. Indeed, it could be from a theoretical point of view, that the smaller ladder width, the stiffer it will be and hence the it will be. It is a fact that the cable steelwork .01i,:h the CEGB employs has considerable reserve noth over design loadings. ,ir Because the ladder racks are manufactured in standj 6 metre lengths, splice joints are required. A ladder 1 li ce consists of a 200 mm long piece of 8 mm thick steel bar with four M12 tapped holes equally .raced along it. The bar is sized such that it will slide Alio the end of the C3 channel which forms the rail t h e l a dder. With this bar positioned centrally be!\N ecn the two ladders to be joined, the M12 screws .rc tiQhtened down into the splice bar and on through a until they contact the bottom of the ladder rail. they are tightened still further, they begin to del'orrn the bottom of the side rail; all four screws are li ghtened to produce the same degree of deformation. he deformation of the channel in this way forms a mechanical key which prevents relative slip. The ladder racks themselves are supported at 2. metre intervals using specially designed cantilever arms. Ilicse arms are in turn mounted on upright supports hich constitute part of the main support structure. 1 typical cantilever arm is shown in Fig 6.71, from [,
which it will be seen that it consists of a length of Cl channel welded to a backplate, the whole being hot-dip galvanised for protection. The backplate is formed from 10 mm thick mild steel plate with fixing holes punched through it. The ends of the backplate are specially cut and bent to fit in between the channel lips when the arm is correctly bolted into place, as shown on the inset detail. This provides a positive location to the connection and also provides some additional lateral stiffness for the joint. It should also be noted that two holes are punched into the backplate, one above the arm and one below it. For normal horizontal ladder rack installation, only the upper fixing hole is used as this provides sufficient slip withstand capability. The lower hole provides additional flexibility for the application of the cantilever arm. The ladder racks do not simply rest in the cantilever arms, they are firmly fixed to them. This is done using Z-brackets as illustrated in Fig 6.72, which shows a ladder assembled on a cantilever arm which is in turn fixed to an upright channel. It is important to note that when the Z-bracket is correctly installed, the head of the fixing screw is below the level of the ladder rungs, hence removing a potential source of damage to cable sheaths during installation. A similar cantilever support arrangement is also used for vertical cable routes. The cantilever arm is of the same design as that shown in Fig 6.71 except that the open face is turned through 90 ° . The presence of two fixing holes removes the need to have 'left hand'
and 'right hand' support cantilevers. Ladder racks are not used on vertical runs because the orientation of the cable removes the need to prevent sagging. Cantilever arms are simply installed at 1 metre vertical intervals and the cables cleated to them. This type of arrangement is shown in Fig 6.73. 6.4 System design and application The basic and most frequently used cable support arrangement is that of the horizontal ladder rack supported at 2 metre intervals on cantilever arms. This
FR , 6.71 Cantilever arm for a horizontal cable route -
FIG. 6.72 Cantilever arm/ladder rack assembly 501
Cabling
Chapter 6
750r1rn
4. C2 CHANNEL
riG.
6.73 Cantilever arm arrangement for a vertical cable route
0
Fic. 6.74 'Double-sided Christmas tree' ladder
is used in dedicated cable areas such as tunnels and flats and it will also be found in plant areas, suspended from concrete ceilings, fixed to structural steelwork and anchored to concrete walls using concrete insert channels. The type of fixing arrangement used will essentially be determined by the quantity of cables to be installed. For major cable routes such as cable flats, the cantilever arms will normally be fixed to C2 channels spanning from floor to ceiling, being fixed at both using the standard baseplate bracket shown in Fig 6.65. Such an upright may be loaded with stacked arrays of cantilever arms on both sides and the resulting assembly, shown in Fig 6.74, is known colloquially as the 'double-sided Christmas tree' assembly. The support uprights could equally be a Cl channel or a C4 concrete insert channel. In the former case, the Cl channel must be fixed firmly to a concrete wall or some other rigid bracing point. The latter type of upright is particularly useful for cable tunnels where cantilever arms can be fixed to both sides of the tunnel, leaving a central walkway for installation and access purposes. The fact that by using concrete insert channels the cantilever arms can be mounted flush to the wall saves valuable space. Cable tunnels are particularly appropriate areas for using concrete insert channels since the required positions of the upright may be accurately determined at a very early stage in the design work. Where such stacked arrays of ladder racks are used, a standard minimum vertical spacing of 305 mm is 502
rack assembly
maintained between ladders. This is sufficient to gain access to install the cables and also to them. The resulting gap also provides enough s, tion to assist in preventing the propagation of a fire from one tray to another. Where cables are required to leave routes, the der racks are always installed on the 'next size up' cantilever arm. Thus, a 450 mm ladder rack would normally be installed on a 600 mm cantilever arm while a 600 mm wide ladder is placed on a 750 mm cantilever arm (there is no 750 mm wide ladder). The ladders are always placed to the outboard ends of the cantilever arms leaving a 150 mm gap which permits cables to leave the ladder at the rear in order to change direction and/or level. The alternative, which would be to allow cables to change levels at the front of the ladders, would produce an unsightly installation and would also dictate that future cables installed on the route would have to be threaded behind the cables leaving the racks, which would be inconvenient. The use of oversize cantilever arms is in fact mandatory for the 'double-sided Christmas tree' support as, without them, the horizontal clearance between the racks on either side of the upright could not be made largeenough to reduce the risk of a fire propagating horizon tally from one tray to the other. In practice, the only areas where oversize cantilever arms are unlikely to be found are cable tunnels. Here,
Cable support systems e will be very little requirement for cables to change level or direction and hence the clearance to the tray of the ladder is not essential and a valuable space . rea r can be made. worth noting that in reality a nominal 600 mm ([ i s cantilever arm is in fact 615 mm long. The ad1 „flo 1:10nal Length is required to achieve sufficient clearance [lie inboard end of the cantilever arm to apply the orrect tightening torque to the ladder fixing screws. is shown 'a Fig 6.72. Where it is necessary for the vertical level of the !,,Jder route to be changed in, for example, a cable flat create the headroom necessary for an emergency cape route, the ladders are angled to maintain the „ al e v ertical clearance (see Fig 6.75). Straight forward angle brackets are used to join the angled ladder .hole io he horizontal ladder. If the angled portion of the run is long enough, special swivel fixing cantilever arms are available to provide support for the ladders over angled portion of the run (see Fig 6.76). ie In addition to being used on the main arterial cable :- ouies across the station, these basic cable support .irrangements are also found in plant areas where much !oer cables are required. Figure 6.77 shows an example ere upward-pointing C2 channels fixed to the top ,urface of a structural beam using B15 beam clamps, riruide the supports from which horizontal ladders be mounted. The same arrangement may equally ther
be inverted and suspended from the underside of a beam as illustrated in Fig 6.78. A variation on the same theme is created by using lengths of Cl channel clamped to the underside of structural beams at 2 metre intervals to form the cantilevers on which the ladder is directly mounted (see Fig 6.79). It is also possible to mount the type of assembly shown in Fig 6.78 directly under a concrete ceiling using suitable concrete fixing anchors or lengths of C4 concrete insert channel cast into the ceiling. Here, the fact that the central upright is supported at one end only, means that the total load carrying capacity must be restricted. In the same way, the vertical channels described above can be used to provide fixings for cantilever arms for vertical cable routes. In dedicated cable risers, these uprights are likely to be concrete insert channels since their required location will be known at an early stage in the design. Closer to plant items, vertical cable runs are quite limited and in these cases the upright would typically be a length of Cl channel surfacemounted on to a concrete wall or braced to a structural steel column. In addition to using ladder racks laid flat in a horizontal plane, they are also sometimes turned edge-on into a vertical plane for horizontal routes. Ladder racks which are orientated in this way may then be bolted flat to walls, onto surface-mounted Cl channels or C4 concrete insert channels. In these cases, the cables are
LADOER RACK TO BE CUT TO SUIT RAKE ANGLE
FIG. 6.75 Method of jointing ladder racks of different planes
503
Cabling
Chapter 6
Fici. 6,76 Swivel cantilever arm
not simply fixed flat against the ladder, as this would require a positive fixing to be made. Instead, specially designed 1-brackets installed at 600 mm spacing are used to carry the cables. These J-brackets (shown in Fig 6.80), are fabricated from a short length of C3 channel with two 6 mm thick plates welded to it at either end, one larger than the other with a fixing hole punched in it. The length of the C3 channel used is either 150 mm or 75 mm (corresponding to two and
one modules-worth of cables respectively). With the J-brackets in place, there is sufficient clearance simpl y to lift the cables into them in much the same way as they are placed on the cantilever arms. The longer of the two end plates of the J - bracket is in fact 150 mm long. This means that it is possible to stack four of these brackets and fix them to a 600 mm wide ladder rack, the top J-bracket being anchored into the ladder rail whilst the other three are fixed to the ladder rung as illustrated in Fig 6,81. If large 1-brackets are used, this gives a theoretical total cable carrying capacity for this arrangement of eight modules (or 56 kg/m), hence illustrating that edge-mounted ladder rails can provide significant cable carrying capacity without protruding great distances from the wall. Where cables pass through plant areas such as the turbine hall basement, it is often the case that there are many obstructions present at ground level, such as pipework and equipment mounting plinths, which pose considerable problems for the cable steelwork layout designer. The problem has two facets; firstly, there is the difficulty of finding a clear route for the cables to follow without the need for excessive bends in the steelwork runs, and secondly, there are the physical problems encountered when installing cable steelwork in congested areas, often requiring complex scaffold arrangements to provide access.
C2 CHANNEL SUPPORT AT INTERVALS OF 2m
C2
CI CHANNEL LENGTH TO SUIT BEAM SIZE CHANNEL TO OVERHANG El 5 CLAMPS 25mm EACH END
Bun
U.BOLT TO AGAINST BEAM FLANGE
MIN BEAM WIDTH 2150mm
F1G. 6.77 Method of fixing cable racking to top of steelwork
504
Cable support systems
U•BOLTS TO BUTT AGANST BEAM FLANGE
U•BOLT TO BUTT AGAINST BEAM FLANGE LADDER RACK TO BUTT AGAINST B'S CLAMP
300rt1m 50rnrn OR 60•Ornm RACK
•;; HANNEL
20Ornm MIN
LENGTH TO SUIT BEAM AND LADDER RACK WIDTHS CHANNEL TO OVERHANG BIS CLAMP BY 25r1m
5.78
Nieihod of fixing cable racking to underside of beams
In order to get round this problem, the CEGB has Jo eloped a number of cable support bridge and tower ,i ,emblies. The use of these bridge/tower combina: wls addresses both of the difficulties identified above. I ir%tly, it is possible to design clear, uninterrupted cable 111IS free from the obstructions at ground level, the ers themselves providing a convenient method of Jropping the cables down to the items of plant which !hey serve. Secondly, it is often possible to carry out rtain amount of 'pre-assembly' of these bridges And towers in site workshops. This reduces the time 'cquired for construction in the congested plant areas, c, wng access free for other contractors. the box section bridges are formed by bolting tolengths of standard ladder rack. Two basic JcNigns of bridge are used, termed light duty and heavy both of which are capable of carrying the same 1 , erzht of cable. The distinguishing feature between heal is that the maximum allowable span for the heavy Jut, bridge is 9 m whereas it is only 7.5 m for the light lit!, bridge. From Fig 6.82, it can be seen that the sides of the L ht duty cable bridge are formed from ladder rack mm, 450 mm or 600 mm wide, depending upon 'Ile number of cables to be carried. These ladders are Joined at the top and bottom by steel bracing straps
Flu. 6.79 Alternative methods of fixing cable racking to underside of beams
-
1
FIG. 6,80 J-bracket
at 600 mm intervals, the bottom strap being staggered with the top for additional rigidity. Standard J-brackets are mounted on the side ladder racks to provide supports for the cables in the normal way. For the heavy duty cable bridge, the bracing straps are replaced by 505
Cabling
Chapter 6
3C0r, PACK
RACK
7SerrnORISOrn.:1 i
FIG. 6.81
BRACKETS
J-bracket assembly fitted to ladder rack
300 mm ladder racks as shown by Fig 6.83. These 300 mm ladders are joined to the side ladders using right angle brackets at 1 m intervals. It is important to note that the 300 mm ladders are provided to make the structure more rigid. They are not there to provide extra cable carrying capacity.
Once assembled, these bridges are supported o n box-section towers. These towers are themselves formed by bolting togethei sections of ladder rack at site but away from the job face. The towers are in fact identical to the heavy duty bridges, 300 mm ladder rack being used for all four sides. Tower heights of up to 6 m (the standard length of ladder rack), are permissible. The standard selection of steelwork components in eludes a range of specially designed gusset and crud. form brackets to facilitate the connection of the bridges to the towers. Some examples of these are shown in Fig 6.84, which illustrates a right angle connection of two bridges to a tower. There are also more elaborate designs of bracket which facilitate angled take-offs of bridges from their support towers. In the main applications for these large cable bridges, the support towers will generally be found fixed to concrete floors using welded baseplate brackets and proprietary concrete anchors. It is however possible to mount the towers on support stools, which are in turn welded to structural RS.1s. This welded fixing is not a preferred solution since it removes some of the flexibility from the steelwork system. It is also considered good engineering practice to reduce on-site welding of structural steel to an absolute minimum. In areas such as boiler houses, there are often many cases where the use of welded mountings is unavoid-
STRAPS ARE TO BE STAGGERED ON TOP AND BOTTOM SIDES AS SHOWN
MAY BE DECREASED WHEN NECESSARY TO ACCOMMODATE SPLICE OR TO AVOID FOULING J.BRACKETS
S
r
NORMAL
3.00mm
30Ornm NOTE
SIDES MAY BE 500.450 500mr, LADDER RACK
Fic. 6.82 Light duty cable bridge assembly
506
Cable support systems
METRE BETWEEN BRACKETS mA , BE DECREASED WREN NECESSARY IC AccommoDATE SPLICE OR TO 55010 j.BRACKETs
NO TE
SIDE kAAy BE In' 455 5CC'" LADDER RACK TOP ANC BC TTD'm RACKS ARE nOrnrn
Flu. 6.83 Heavy &ay cable bridge assembly
Fic. 6.84 Cable bridge/tower arrangement
507
Cabling able. Another variation on the same theme is to mount the towers from the underside of a RSJ using a combination of Cl channels and B15 beam clamps. It is also permissible to fix cable bridges directly to the underside of structural steelwork using the clips described in the previous section. The variety of acceptable fixing arrangements for these box-section bridges all serve to illustrate the overall flexibility provided by the steelwork sysern as a w hole. Because it is possible to install four 150 mm Jbrackets on either side of these bridge sections (for 600 mm wide ladders), it follows that these bridges are capable of carrying significant quantities of cables (up to 112 kg/m). The large quantity of components which need to be assembled to form these cable bridges means that they are a relatively expensive method of supporting cables. It is therefore important to ensure that these bridge/tower arrangements are only specified if they are to be well loaded. There is, however, a significantly cheaper bridge/ tower combination which may be used for routes with few cables. This is known as the 'tee tower' assembly and it provides a method for supporting a single 300 mm ladder rack laid horizontally over spans of up to 6 m at up to 6 m above the floor. In this arrangement, the towers are formed by bolting together two 300 mm ladders to form a tee-section upright. These ladders are in turn fixed at top and bottom to a special `baseplate' assembly. The 300 mm bridging ladder is then fixed to the top surface of the upper 'baseplate', the cables being cleated to the top of this ladder in the conventional way. Two reinforcing channels are usually fixed to the underside of the horizontal ladder to provide additional rigidity. Where spans of up to 4 in are required, these reinforcing channels are of the Cl pattern, If 6 m spans are required, C2 section channels are used to provide the necessary strength. Despite the relatively long spans and simple tower construction, these tee tower assemblies still have a very high steelwork-to-cable carrying capacity ratio and they are not, therefore, considered to be very cost effective. Alternative cantilever arm based cable support arrangements will therefore be used in preference if fixing positions are available. If the use of a tee tower is unavoidable, then an attempt is always made to open out the support tower pitch to the maximum permissible by using C2 reinforcing channels. A typical tee tower assembly is shown in Fig 6.85. The tee tower assembly described provides a means for carrying three modules-worth of cables (21 kg/m). Where support for even smaller quantities of cables over elevated routes is required, the cable steelwork system provides small U-brackets which can be bolted directly to Cl and C2 type channel. These U-brackets, illustrated in Fig 6.86, are similar in design to the J-brackets described earlier, consisting essentially of a short length of C3 channel with plates welded to it at either end. A 150 mm wide U-bracket provides the capacity for 14 kg/m of cable whilst 7 kg/m capacity 508
Chapter 6
MAX SPAN
Am
C.2
-
MAX 3COTT, , LADDER SACK WITH CI OR C2 CHAhNEL REINFORCING
EE TOWERS CONS - R 1,01" .F.D FROM 3C0mr, LADDER RAC*
FIG. 6.85
Typical tee tower arrangement
FIG. 6.86 U-bracket arrangement
is provided by a 75 mm wide bracket. Overhead cable bridges are formed simply by bolting these U-brackets to lengths of either Cl or C2 channel at 0.6 m intervals. If a Cl channel is used, the maximum permissible span is 4 m, a C2 channel increases this to 6 m. By virtue of the very small cable carrying capacity, this type of cable support arrangement is generally referred to as being 'tail end steelwork' and is used to support cables over the tail ends of their routes as they approach the equipment to which they connect. The important features of tail end steelwork are that:
Cable support systems •
•
It carries very small quantities of cables. The arrangements used are designed at site, usually by the cable installation contractor, to suit the physical conditions which prevail where the cable is to
he routed. Tai l en d s teelwork does not form part of the com• puter matrix used to provide the automatic routing fac ility. For this reason, tail end steelwork is somemes referred to as 'off matrix steelwork'. ti The flexibility provided by the construction kit based , te elwork employed by the CEGB means that there is ery large number of tail end steelwork configuraa v tions to be found in modern CEGB power stations. The basic cable carriers which are used for tail end steelwork are: • J-brackets. • U-brackets. • 300 mm ladder racks. • Perforated cable trays. Of these, the perforated cable tray is the only one kkhich has not been mentioned before. The perforated tray is a proprietary cable support product and is generally of the form illustrated in Fig 6.87. This type of cable support is inexpensive because it has no welds
• The solid base prevents cables from being routed out through the bottom of the cable carrier. • The solid base restricts the flow of air round the cables, hence losing a high proportion of the available convective cooling. • The upturned lip provides an obstruction to cables leaving the ladder rack. This subsection has described the various cable steelwork assemblies which are commonly constructed from the basic range of steelwork components. It has illustrated that cable carrying capacity is based around a 7 kg/m 'module' and that standard arrangements are available to support from one to 16 modules of cables. Table 6.22 draws all these standard assemblies together into a single ready-reference chart. A chart such as this would he used by the cable steelwork layout designer when selecting the best type of cable support steelwork for a particular application. By providing standard support assembly designs, it is possible to draw up a coding system which greatly si mplifies cable steelwork layout drawings. The CEGB uses a coding system based upon the standard assembly figure numbers appearing in GDCD Standard 197 for the preparation of its cable steelwork layout drawings.
6.5 Seismically qualified cable supports Before leaving the subject of cable support steelwork, it is worth covering briefly the topic of seismic quali-
E:GING SiRIP WHEN REQUIRED
Fin. 6.87 Perforated cable tray In its construction. ft is also very easy to work with
at the very small capacity sizes required for tail end teelwork. Perforated tray steelwork is available in the same sizes as the standard ladder rack, but it is not used in preference to ladder racks where that is Justified because it is inferior to ladder rack on the following counts: • It has a higher self-weight to cable carrying weight ratio (and is therefore less cost-effective). • It does not provide convenient cable cleating facilities.
fication and its impact on cable support steelwork design. Essentially, seismically qualifying a cable installation requires justification that the cable support steelwork stays intact and in place during the defined seismic incident and also that the cables remain on their support steelwork. Because of the huge variety of cable steelwork assemblies which will be required for a typical power station cable installation, seismic qualification by full scale test is impractical. By virtue of their frame-like modular construction, cables support steelwork assemblies are most suitable for seismic qualification by mathematical analysis. Complex finite element mathematical computer models are prepared for representative or worst-case assemblies in order to predict the behaviour of the real assemblies during the earthquake. The lengths of channels and the ladder racks are modelled as beam or strut elements whilst the fixings and connections are modelled as translational and/or rotational springs. In many cases, static load testing is used to determine the spring stiffness values for the various connection types. It is important to realise that the term seismically qualified can only he applied to the cable steelwork assemblies and not the components which go to make up those assemblies. Also, as with the seismic quali509
Cabling
Chapter 6 TABLE 6.22 Guide to selection of steelwork structures for various modules
Horizontal
Vertical
No. of Max span
Type of structure
Cl channel — cables laid in channel or in 75 mm U-bracket
4m
CI channel
6m
C2 channel — cables laid in channel or in 75 mm U-bracket
6m
C2 channel
4m
Cl channel — cables laid in 150 mm U-bracket
4m
Cl channel
6m
C2 channel — cables laid in 150 mm U-bracket
6 in
C2 channel
1m
300 mm cantilever
l m
450 mm cantilever
1m
600 mm cantilever
modules
Maximum span
L p io I
4m
Up to 2
Type of structure
2m
300 mm ladder rack (laid flat)
4m
300 mm ladder rack (laid flat) — reinforced with Cl channel
6m
300 mm ladder rack (laid flat) — reinforced with C2 channel
Up to 4
2 in
300 mm ladder rack — on edge with 2 x 150 mm J-brackets
Up to 5
2 in
450 mm ladder rack — laid flat
Up to 6
2m
450 mm ladder rack — on edge with 3 x 150 mm 3-brackets
Up to 7
2m
600 mm ladder rack — laid flat
Up to 8
2 in
600 mm ladder rack — on edge with 4 x 150 mm 3-brackets
Up to 3
Up to 12
Up to 16
Note:
7.5 m
300 mm light duty bridge with 2 x 150 mm 3-brackets on each side face
9m
300 mm heavy duty bridge with 2 x 150 mm 3-brackets on each side face
7.5 at
450 mm light duty bridge with 3 x 150 mm J-brackets on each side face
9m
450 mm heavy duty bridge with 3 x 150 mm I-brackets on each side face
7.5m
600 mm light duty bridge with 4 x 150 mm 3-brackets on each side face
9m
600 mm heavy duty bridge with 4 x 150 mm 3-brackets on each side face
For module requirements greater than those stated in the tab e, use multiples of the system. With 40 modules of cabling use six levels of 600 mm ladder rack on cantilever arms.
fication of other equipment, the seismic qualification will relate to the particular design earthquake conditions being assumed. For normal non-seismic applications, cable steelwork structures and their fixings have only to be designed to withstand the normal loads imposed by gravity acting on the cables and the self-weight of the structures 510
themselves. The major difference which needs to be catered for in order to survive a seismic disturbance is resistance to horizontal accelerations. At Heysham 2, which was the first CEGB power station where certain plant items were specifically designed to withstand , the effects of an earthquake of prescribed magnitude the most significant effect on the design of the cable
Cable support systems steelwork was the increase in the cross-sectional f most of the main upright members which, in areas o urn, increased their stiffness. This effect is seen most Jramatically by the comparison of the floor to ceiling upright members for non-seismic applications with for seismic applications (shown in Fig 6.88). The hose uprights are shown drawn to the same scale. [
The solution, therefore, was to design the floor and ceiling fixings with pinned connections since a true pin connection can transmit no moment. Using these fixings led to much lower loadings on the concrete anchors and lower stresses in the uprights. The pay-off from using this fixing method is that it permits greater movement in the cable supports. The requirement for special civil connections and for large upright sections essentially stemmed from the approach used for seismic qualification at Heysham 2, which was to start with the established format of steelwork and determine what needed to be done to obtain the ability to withstand the seismic disturbance. This approach was adopted for a number of reasons: • The design permitted retention of the cantilever type support arrangements. This in turn enabled the same cable installation practices to be used for the seismically qualified areas of the power station as those used for the non-seismic areas and, as for previous stations, to run the cables out adjacent to the route and then lift them into place.
N O N-SE, S MIC
• Adopting the same basic steelwork format permitted the existing computer-aided cable routing programs to be used with very little modification. 44 3mm
• The same cleating methods could be used for both seismic and non-seismic areas. • Interface compatibility between non-seismic and seismic cable steelwork was assured.
11 3mm
1 00mm
41 Irnm
S EIS M IC
Fir,. 6.88 Comparison of floor to ceiling upright supports for non-seismic and seismic applications
Another area of impact on the steelwork was that ,11 . the civil connection design. The high moments generated by the horizontal loadings in the steelwork
.memblies led, with conventional fixings, to very high pull - out loads in some of the concrete anchors. In a \.onventional fixing', it is assumed that the objective ro clamp the steelwork baseplate as rigidly as possible [o he floor/ceiling and hence make the connection as srtr as possible. However, in an assembly where the .ounections at the floor and ceiling are stiff (built-in Lon nections), much higher stresses in the upright, and hence greater moments at the fixings, are generated.
,
The decision to employ cantilever type steelwork also had penalties, chiefly resulting from the required increase in structure stiffness. The upright members in the support frames became very heavy, expensive, and ti me consuming and labour intensive to install. The fixings to the civil structure were also very heavy and expensive due to the high load capacities required from them. The main difficulty arises in accommodating the flexibility brought about by the use of the cantilever type cable ladder supports. An alternative approach which is being used at Sizewell B is to use closing struts to form trapezoidal supports for the cable ladders. The effect of adding the closure strut is to produce a much stiffer framework as far as horizontal loadings are concerned. The increased stiffness means that standard cross-section members can be used, these trapezes usually being assembled using C2 channel. Simply adding the closing strut is generally not sufficient in its own right to achieve seismic withstand capability, and in many cases additional bracing struts are needed to achieve the required rigidity. The main advantage in going to this system is that the frameworks are much easier to handle since they are lighter. Because, in general, they make use of standard components they are also cheaper than their cantilever counterparts. The major drawback is of course that cable installation is no longer straightforward 511
Cabling
Chapter 6 m
mEll
since cables now need to be threaded through the trapezes. The use of trapeze type supports will also mean that for a given cable carrying capacity, the support structure will also occupy a greater volume. This may have implications for civil structure costs for areas such as cable tunnels. Finally, it is important to appreciate that a seismic withstand requirement will also have an impact on the design and installation of tail end steelwork. The need to demonstrate by mathematical analysis that a cable support will stay intact during an earthquake and the inherent design work and time which this requires, will mean that it is not possible to leave the design of tail end cable steelwork as a site activity. Every tail end steelwork cable support assembly which is required to survive the earthquake must therefore be designed in advance. In order to reduce the costs of this seismic qualification activity, it also becomes necessary to impose limits on the number of designs of tail end steelwork which may be used. I mposing these limits means that some adaptations of designs may be necessary to suit particular applications at site. This often leads to provision of tail end steelwork with a greater load carrying capacity than required for the application, incurring a hardware cost penalty. This is, of course, offset by the savings which result from not carrying out further qualification analysis. Because of the relative simplicity of the tail end support structures it is, however, possible to use si mplified methods of analysis and thereby produce qualified steelwork designs more cheaply.
7 Cable installation practices
7.1
Introduction
This section primarily describes the CEGB's 'cable cleating philosophy' and its origins, i.e., the manner in which cables are permanently located on their support arrangements. As described in the previous section, the bulk of cables in a power station are installed in air on cable supporting steelwork and this is the method on which the most emphasis is placed. The other installation options are: • Installed direct-in-ground. • Installed in ducts. • Laid in concrete troughs. Before the cables can be permanently cleated to their support steelwork, however, they must first of all be transferred from the drums on which they are delivered to site. This process is known as cable pulling and it is dealt with in Section 7.6 of this chapter.
7.2 The need for cable restraint The fundamental reason for restraining cables is simply 512
to provide a means for their location. In the horizontal direction this basically means leading the cables along the correct paths, while vertically it is also necessary t o support their weight. This is true irrespective of th e type and size of cable. There are, however, two further factors which need to be considered when designin g cable cleating arrangements for power cables. Under normal load conditions, conductor pow er losses dictate that there will be some thermal expan_ sion of the cables and, to allow for this, cables are never anchored to structures as they pass round bends, However, since many power station electrical loads are intermittent there is, in many cases, also an element of thermal cycling which needs to be allowed for by the cleating system used. Over and above these thermal requirements however, there is for the single-core power cables used for large energy transfers across the power station, the need for restraint against the large electromagnetic forces generated under shortcircuit conditions. These large forces do not necessitate cleating of multicore power cables for two reasons: • Circuits fed using multicore power cables are fuse. protectedand the magnitude of the fault current, and hence the bursting forces generated, are limited by the presence of the fuse. • Any forces which are generated between the phase conductors are restrained by the construction of the cable itself. The forces which are exerted on a single-core power cable are negligible under normal full-load conditions (typically I kgf per metre, dependent upon the installation configuration used). Under through-fault conditions, however, forces measured in many thousands of kgf can be generated for periods of the order of I second. The cable restraint system used for single-core power cables must therefore be capable of controlling these forces in order to minimise the risk to human life and damage to adjacent plant and the cables themselves. For single-core cleat design purposes, a current of 121 kA asymmetric first peak, decaying to 39.4 kA RMS symmetrical in not less than 150 ms is assumed. This is based on a 750 MVA fault on the 11 kV system, reinforced by contributions from rotating plant. Assuming that the main protection functions correctly, then the clearance of that fault will take place within 0.5 seconds. Should main protection fail to operate, the fault will be cleared by the back-up protection but with considerably extended clearance times. However, neither main nor back-up protection operation ti me is used as the design parameter for single-core power cable cleats; instead, the performance capability of the cables themselves is chosen as the limiting factor. The elastomeric cable insulations employed in the CEGB approved range of single-core cables (at all three auxiliary system voltages), are capable of withstand ing a short-circuit maximum conductor temperature of 250 ° C. To ensure compatibility with the design Per"
Cable installation practices •Irmance of these cables, therefore, the cable cleating riarvernents are designed to restrain the cables under lit. f,Uilt conditions for the period of time necessary for e conductor to reach this limiting temperature. This •: i r.; all practical conditions since the cable size will % c been selected to match the system protection pircinenrs. Putting numbers to this, certain types ,,:, restraints must be capable of withstanding an [rial shock approaching 9000 kgf on one conductor n a,hioned somewhat by the cable itself), and then an 1.. latorv load of around 3000 kgf. (Implicit in the ti,ures is an assumption about the formation of cables within the clamps and this point is addressed .
0
Luer.) These short-circuit loading figures are, however, used design guidelines only. Full scale short-circuit testing , u sed to demonstrate conclusively the adequacy of a ,articular design of cable cleat. In summary, therefore, there are three possible reafor providing restraint for cables. Which of these . 0116 pply depends upon the cable type being considered. er, for all cable types, the cleating system used [ 10„ e ust provide the most economic method of fulfilling li :he design functions reliably during the life of the power s;.iiion. The methods which are used by the CEGB in ; , ractice are discussed as follows. 1
j
7.3 Cable cleating design parameters s;inde-core power cables may be installed in either a 1rc1oil group' or a 'flat spaced' arrangement. In the ircfoil formation, the three individual phase cables are triangle, sheath to Jeated together in the form of in flat formation, as the name implies, the sheath. ,,ihIcs are laid side-by-side. In cases where there is a neutral cable, this is either laid alongside the trefoil :- 1/4mir) or forms a fourth cable in the flat formation. Hell installation formation has its own advantages ard disadvantages. The trefoil group, because of the ,[() , e proximity of the conductors, is subject to very i h bursting forces under conditions of through fault .. ,,irrencs. In addition to this, under normal load con.!]:ions, the trefoil arrangement reduces the current ...irr!.ing capacity of the individual cables due to the Auced heat radiating surface area. A further dis.ki‘antaee is that handling problems make it difficult 'a [a!, up the trefoil arrangement for larger single-core ...ihles. In contrast to this, the flat spaced formation . . duces bursting forces considerably, allows full use of :tie prospective current rating of the cable and is very •. ;mr.)1e to lay. Furthermore, the cleats for the flat spaced :ornialion are of a much simpler pattern than those ,,quired for the trefoil configuration and are therefore 'L•Ns e■ pensive. T he Hat spaced arrangement, however, suffers from .
a
-
-
IL
disadvantage of generating a stronger, less homo:= "cous, magnetic field, hence leading to current inahal:ince difficulties in multiconductor per phase circuits higher sheath voltages, This effect also in-
and also
creases the cable impedance. Installing the cables in this way will, of course, also take up a greater space on the support arrangement. At the moment, CEGB policy accepts that the advantages of the flat spaced formation outweigh its disadvantages and this is the installation method which is therefore used. The issue is continually reviewed in the light of experience and technological developments in cleat design and it is possible that, in the future, the trefoil group may he favoured for some installations.
7.4 Cleating philosophy for cables installed on steelwork Both cable type and run orientation will have major influences on cable cleating philosophy and the CEGB therefore lays down rules governing cleating arrangements for all of the main cable types in the three major run orientations. These run orientations are: • Straight horizontal runs with the cables supported on ladder racks. • Straight vertical runs with the cables fixed directly to cantilever arms. • Horizontal runs in a vertical plane (i.e., with the ladder rack mounted edge-on). Guidelines are also given for cleating at bends, cleating below equipment and for cleating at single-core cable transposition points. These are, however, rather beyond the scope of this text which will therefore only concentrate on the three major groups above. Readers requiring further information on these arrangements should refer to GDCD Standard 216 [21]. 7.4.1 Straight horizontal runs on ladder racks
Single-core power cables are rigidly clamped to the support ladders using plastic coated, steel zig zag cleats, of the type shown in Fig 6.89, spaced at 1.2 metre intervals (i.e, alternate, upward-facing ladder rungs). A single size of cleat is used for all sizes of cable and the design ensures a centreline spacing of 80 mm. To reduce chafing of the cables due to thermal cycling, a plastic insert is placed into the open face of the ladder rung underneath the cables. Further protection is also provided by the plastic coating of the cleat. Multicore power cables are installed on ladder racking without clamping hence permitting the required thermal movement to take place. An additional bonus arising from the lack of clamping is that installation costs are also reduced. In these cases, location is achieved by means of a device known as a thermal spacer. This spacer, shown in Fig 6.90, is a polypropelene peg of 25 mm diameter, with a specially designed foot profile which enables it to be locked firmly into place on a length of cable -
513
1PIPP Chapt er 6
Cabling
(8)
• They provide an easily installed method of restr a i n. ing the lateral movement of cables. NUT
CQA) WASHER
• They provide a simple method of obtaining a 25 m in spacing between adjacent cables to allow air cireui a. . tion, hence avoiding cable derating. • They provide a simple means of installing the linear heat detecting cables used for fire detection pu t-. poses in CEGB cable installations. The therm a l spacers are locked into place on the underside of the ladder such that the detector cable protects the cables on the ladder immediately below it. The de. tector cables are simply laid into the slot in the barrel of the spacer, some local protection being given to the detector cable by using a short length of spli t silicon rubber tubing. A longer design of thermal spacer to that shown in Fig 6.90 also exists to support a detector cable above the topmost ladder rack of a stacked arrangement. Further information about the operating principles of linear heat detecting cables can be found in Section 3.8 of this chapter.
CHANNEL INSERT COVER STRIP
CHANNEL OR LADOER RACK
Fici, 6.89 Multiple zig-zag cleats for single-core cables
Multicore power cables, up to and including 16 mm 2 conductor size, are installed touching in a double-layer located by these thermal spacers along the rails of the ladder work at 1.2 m intervals. Larger cables are installed in a single-layer with a thermal spacer between each cable, hence providing the required air gap (see Fig 6.91). Control and instrumentation cables require no cooling and hence can be installed touching, irr. -: - ;m:tive of size (see also Fig 6.91). Again they are refon their support ladders by thermal spacers l.' in the rails. Cables up to and including 12-core core and 60-pair multipair, are installed in a dot yer. Cable sizes larger than this are installed in :glelayer due to their physical size and weigh Ihese installation rules also serve to limit the amount of combustible mass carried by the ladder rack which is important from the fire propagation point of view. It is worth noting that where the cable installation is to have a seismic withstand capability, the short, polypropelene thermal spacers are not adequate. Two problems exist: • The weight and movement of the cables during an earthquake can be such that they can snap the spacers at the narrow part of their foot profile. • The movement of the cables can be so great that they can jump over the short spacers.
FIG. 6.90 Thermal spacer
support channel, simply by twisting it. These thermal spacers fulfil three functions: 514
To overcome these problems, the CEGB has developed a special high strength thermal spacer, made from super-tough nylon, which is also twice the height of the standard thermal spacer. When installing control and instrumentation cables it is also necessary to consider the possibility of adjacent power cables inducing interference currents in
Cable installation practices
ZIG-ZAG mULTIPLE CLEAT ARRANGEMENT 1. SINGLE CORE POWER CABLES SINGLE COPE POWER CABLES
LADDER RACK
1 200n1m
ARRANGEMENT2: MULTICORE POWER CABLES SHORT THERMAL SPACERS
MULTICORE POIR CABLES ISmen AND BELOW LADDER RACK
1209mm
MULTICORE POWER,. CABLES ABOVE lEmm
SHORT THERMAL SPACERS
CONTROL AND INSTRUMENTATION
LADDER RACK
CAKES
ARRANGEMENT 1: MULTICORE AND MULTIPAIR CONTROL CABLES
1000mm
FIG.
he
6.91 Horizontal cable cleating arrangements for multicore power and control cables
control cores, particularly under fault conditions. io avoid this, the CEGB dictates that, for all major horizontal or vertical cable routes, where power cabling or C and I cabling is run in parallel, a minimum Ph!rsical separation of 600 mrn'is maintained between
the power and control cables. This requirement is relaxed to 300 mm if no single-core power cables follow the route. For ease of installation and cost reduction, this separation ruling is furthermore relaxed at the tail-end of the cable routes for multicore power 515
Cabling
Chapter 6
cables, provided that the parallel length does not exceed 5 m. Having separated C and I cables from power cables, it is always considered good practice to install the power cables on the uppermost racks of a stacked array to reduce unnecessary heating, and hence thermal ageing, of the control cables. 7.4.2 Straight vertical runs on cantilever arms
Cantilever arms are installed at 1 m intervals on vertical cable routes and the cables are therefore cleated to every arm. Zig-zag cleats are not used to anchor single-core cables on vertical runs for two reasons. First, it is not possible to guarantee that the dead weight of the middle cable (or cables if a neutral is present) will be adequately restrained if, for example, the two outside cables in the cleat had slightly larger outside diameters. Secondly, it creates unacceptable installation difficulties in simultaneously lining up three large power cables side-by-side on a vertical run. Instead, individual cast aluminium, two-part claw cleats of the type shown in Fig 6.92 are used in conjunction with a steel bracing
NON MAGNETIC SPACING STRAP
CLEATS USED IN PAIRS NOTE DISPOSITION OF CLEATS
SPACING STRAP FITTED BETWEEN CLEATS AND ARM
:HANNEL NUT . CHANNEL ARM
strap to provide rigidity under short-circuit conditions. The cleats are aluminium and not steel in order to avoid the large currents which would circulate in the cleat due to the creation of a magnetic circuit around the cable. The effects are very much smaller where the magnetic circuit loops all three phases of a circuit since a magnetic balance will virtually exist. This is therefore not a problem in the case of the zig-zag cleats used on the horizontal runs. It is for this reason that the bracing strap used with claw cleats must alway s be placed between the cleats and the cantilever arms rather than above, bridging between the top of the cleats, since the fixing bolts would then create magnetic circuits around the individual cables. These individual claw cleats are, of course, more expensive than the zig-zag cleats and they are also more time consuming to install. They are therefore not used on horizontal cable runs. Vertical runs of multicore power cables with conductor sizes of above 16 mm 2 are clamped singly, using a single pressed steel cleat of the type shown in Fig 6.93. This type of cleat has the advantage of a specially shaped foot which fixes around the lip profile of the cable support channel. The act of tightening-up the cleat onto the cable serves to lock the cleat in place. This leads to much faster cable installation than using the claw type cleat. A range of cable sizes is covered by one cleat size which is also a major advantage. Such a cleat would not, however, be capable of withstanding the forces associated with a short-circuit and they must not therefore be used for cleating single-core power cables. Cables of 16 mm 2 conductor size and below are strapped at 1 m intervals in bundles using a specially designed, two part, polypropelene cable tie (similar to conventional cables ties). These ties have specially
SHAPED METAL PLATE TO CLAMP CABLE ADLILISTED BY SET SCREW
SEPARATE SHAPED PLASTIC COUNTERBED HELD IN POSITION BETWEEN CABLE AND CHANNEL ARM
MIO 95mm FiXiNG STUD SECURES EACH PAIR OF CLEATS AND SPACING STRAP TO ARM WITH CHANNEL NUT
EXAMPLE OF USE OF CLEATS FOR 3 SINGLE CORE POWER CABLES SPACED AT BOrnm CENTRES
HOLES FOR MIC FIXING STUD
FIG. 6.92 Claw cleats for-single-core cables
516
CLEAT HOOKED ON TO INSIDE OF CHANNEL ARM
FEG. 6.93 Pressed steel cleat
Cable installation practices shaped hammerhead ends which locate under the lips -4 the cable support channel. Again, tightening the .leat fixes the strap in place. vertical cable routes which exceed 10 m, every For strap is replaced by a pressed steel cleat of the above. This provides more positive sup;„ r e described r.or[ for the cables. ,„:eption of the very largest control and \ sun t h e ex
,11,iriurnentation cables, the same installation method
for the small rnulticore power cables above traps and pressed steel cleats). The large con, s are cleated singly at I m intervals using the r)l pre—ed steel cleats. These cleating arrangements are illusirated in Fig 6.94. used as
7.4.3
Horizontal runs in a vertical plane
In this situation the support ladder rack is mounted ,p e .on, flat against a wall for example, or forming he side member of a support bridge. in oeneral, cables will be supported on i-brackets K)Ited onto the ladder rack at 0.6 m intervals. The are then laid in the i-brackets and cleated as !he\ %%mild be for straight horizontal runs. The exception to this is single-core power cables , ■ Irch are cleated directly to the outward facing ladder rungs at 1.2 m intervals, using the claw type cleats .lion.kn in Fig 6.92 in conjunction with the steel backing sirips. This arrangement is illustrated in Fig 6.95.
7.5 Installation practices for cables installed other than on support steelwork the three alternatives to installing cables on support siechwrk mentioned in Section 7.1 which are used by
he CEGB are: • Burying them directly in the ground. • installation in ducts. • Routing in concrete troughs. 1.iich is covered briefly as follows.
7.5.1 Direct in ground [his installation method is obviously only applicable
!or cables routed externally to the main power station
Hiding. Only a very small proportion of cables on a modern power station are buried directly in the ground.
When routing cables in this way, the main consideration will be to reduce the risk of damage to the hurled cables from subsequent excavations. This is line by first of all selecting the route for the cable hat it will be subject to the minimum possible :inure disturbance. It is recognised, however, that exflaiions are often carried out on power stations sites iLiring their operational life and that other measures ire also necessary. ,
The main protection is provided by ensuring an adequate depth of burial. For cabling up to and including 415 V, the excavated trench for the cable is cut deep enough to ensure that the highest point on the cable is not less than 500 mm from the surface. For cabling at 3.3 kV and 11 kV, the corresponding figure is 800 mm. Where multi-layering of cables is necessary, the depth of trench is simply increased to ensure that the above limits are maintained for the uppermost layer. Before the cables are laid, a 75 mm thick layer of sand is tamped down into the bed of the trench. This sand layer is used primarily to provide a cushioned surface against the cable sheath, free from stones or other protrusions which could cause damage. After the cables are laid, a further 75 mm layer of sand is used to cover them on top of which protective concrete trench covers, clearly marked to identify the presence of the cables below, are placed prior to backfilling. Marker posts are then placed at strategic points along the cable route to provide an additional degree of protection. Finally, drawings of all external cable routes are prepared on completion of installation for reference when future excavations are required. 7.5.2 Installed in ducts
Routing through ducts is sometimes used as an alternative to direct burial for outdoor routes, particularly at road crossings and similar locations. They are also
used in limited instances within the main building where cables pass through walls. The ducts which are used by the CEGB are either of the unglazed fine earthenware type or, alternatively, plastic. The formerly-used glazed earthenware type ducts are no longer readily available. When designing ducted cable routes it is important to make the runs as short and as straight as possible as this will greatly ease cable installation. Any unavoidable bends in the route must be of a larger radius than the minimum bend radius of the cables to be pulled through them and, ideally, should be of as large a radius as practicable. During installation, care must be taken to ensure correct alignment at duct section joints, as this could cause damage to cable sheaths during cable pulling. Having installed the duct, it is also important to ensure that any debris is removed from it before attempting to pull cables through. This is done by pulling an appropriately sized bobbin through the duct. 7.5.3 Routing in concrete troughs
The major disadvantage with burying externally routed cables directly in the ground or in routing them through
ducts, is the difficulty involved when installing additional cables later along the same route. For the bulk of outdoor routes around a power station site, particularly in areas such as substations, cables are therefore 517
Cabling
Chapter 6
ARRANGEMENT 1;
SINGLE CORE POWER CABLES CANTILEVER ARM
ARRANGEMENT 2: POWER AND CONTROL
muLTIconE
CABLES
CANT , LEVER ARM
TSINGLE CLAW CLEATS WITH SPACING STRAP
LARGE MULTICORE POWER OR LARGE C AND I CABLES NOT MIXED ON THE SAME CANTILEVER ARMS)
WHERE A VERTICAL CABLE RUN EXCEEDS CI M A PRESSED STEEL CLEAT IS USED ON EVERY THIRD CANTILEVER ARM .
SMALL MULTICORE POWER OR C AND I CABLES (NOT MIXED ON THE SAME CANTILEVER ARMS 000mm
F[G. 6.94 Vertical cleating arrangements for single-core and multicore cables
installed in preformed sectionalised concrete troughs. These troughs also provide protection for cables installed in areas liable to settlement where directly buried cables might be damaged. The trough types used by the CEGB have a Usection and they are provided with close fitting concrete lids of the reinforced pathway type. Three basic sizes are used: • 685 mm wide x 345 mm deep. • 360 mm wide x 205 mm deep. • 175 mm wide x 215 mm deep. Cable cleating within these troughs depends upon the cable type. For both straight runs and bends, control 516
cables are laid direct into the base of the trough, being neither cleated to the trough nor to one another. For power cables in the two large sizes of trough, lengths of cable support channel are installed in the base of the trough at 1 metre intervals although they are not anchored down to allow for some settlement. Single core power cables are cleated to these channels using the zig-zag cleats at 2 metre intervals. Where multicore power cables are installed in troughs, they are laid on the channels spaced using thermal spacers at 1 metre pitch for cables of 35 mm 2 size and above. Where the number of power cables is sufficient to warrant their use, J-brackets are mounted on the walls of the trough down each side. The cables are installed on the brackets in the same manner as for normal
Cable installation practices
LADDER RACK
3 SINGLE CLAW CLEATS WITH NON.MAGNETIC SPACING STRAP
6.95
Cleating arrangement for horizontal runs of single-core Cables in a vertical plane
...cl ,Aork runs. In the smallest size of trough, the sr cables are simply laid direct into the trough base 2 Lt used for cables of 35 mm or above, only one • he installed since there is no means of providing hiist the use of concrete troughs might appear •,ir:[cularly appropriate in and around transformer
mpounds, experience has shown that they can become •-,irs or transformer oil which will, in the long term, damage to cable sheaths. In such areas, cables are tIled either in ducts or, alternatively, if concrete •7. , LH2.li) or trenches are used, after the cables have .;:n laid they are filled with sand and covered with a • , n,rete screed. •
,
-
7 6 Cable pulling pulling is the term used to describe the way
hich
the cables ore transferred from the drums they are delivered from the manufacturer :hcir permanent support arrangements. Again, this • • eclion concentrates on cables installed on support as these constitute the bulk of cables in .. .Jern power stations. lie term pulling derives from the fact that the cable phHcally pulled from its drum during installation. '. ii!st his may sound a very straightforward pro...Jure, it must be appreciated that a cable is more !0 sustain damage during installation than at I i other time in its working life. There are therefore .7:ain basic rules which must be adhered to during installation in order to minimise the risk of cable '.1 l och l
i:\ cable can sustain damage during installation in umber of ways, the most obvious of which is by
having an excessive tensile load applied to it during pulling. This type of loading can cause relative slip between the concentric layers of the cable, possibly causing waisting in the insulation materials which could lead to premature breakdown during operation. This is particularly critical for 11 kV cables. For smaller cables, notably C and I types, excessive tensile load can break individual conductors. If a cable has been subjected to excessive pulling tension during installation, stretching of its polymeric components may well have occurred, particularly the sheath. This stretching may subsequently relax during service and expose the armours at the glands, a phenomenon referred to as sheath retraction. This may then affect the integrity of the cable gland.
To avoid the problems caused by the application of excessive tension, maximum allowable pulling tensions are quoted by cable manufacturers for each cable type and size. These figures depend upon conductor material and cross-sectional area, although cable construction is also significant. In a multicore cable, for example, the tensile load is unlikely to be distributed evenly between the conductors. The maximum allowable pulling tension figures must take factors such as this into consideration. It is also important to take care when pulling cables around bends as the cable is being successively bent and straightened as it passes over the bend. This applies a tensile load to the outer part of the cable and a compressive load on the inside. The smaller the bend radius, the greater will be the tension on the outer portion of the cable and hence the greater will be the tension required to pull the cable round that bend. Similarly, for a given bend radius, the larger the cable diameter the greater will be the tensile load generated. Furthermore, as the cable passes round the bend, a reactionary force will be set up at right angles to the cable major axis, the so-called sidewall pressure (see Fig 6.96). This reactionary force will have a crushing effect on the cable and in the extreme may cause damage such as, for example, rucking of tape screens in multipair cables. This type of damage is avoided by specifying minimum allowable bending radii for each cable type and size. These minimum bending radii are usually expressed in terms of the overall cable diameter.
ffiL
TENSION
SiOEWA1L PRESSURE
FLG. 6.96 Diagram showing sidewall pressure 519
Cabling
Chapter 6
Furthermore, the sheath of a cable could sustain damage if it were to be dragged across any sharp edges or rough surfaces during installation. In these cases, rollers and skid plates such as those shown in Fig 6.97 may be used to lift the cable away from the hazard and hence prevent scuffing. As an additional precaution, the CEGB has devised mechanical tests (see Section 3.11 of this chapter) to demonstrate that the cables which are used in modern power stations have some degree of resistance to this type of damage.
HOOP
ROLLER
SKID PLATE ROLLER
FIG. 6.97 Typical rollers and skid plates
Pulling cables into ducted runs brings with it its own unique problems, mainly due to the restricted space within the duct and the inaccessibility of the cable once the pull has commenced. These problems become worse as the length of duct run increases. In addition to the number of, and radius of, the bends in a ducted run, the force required to pull a cable through a duct will depend upon the coefficient
of friction between the cable sheath and the inner surface of the duct. This coefficient of friction can be reduced by the use of proprietary cable pulling lubricants. Care must be taken when selecting such pulling lubricants to make sure that they have no long term detrimental effect on the cable sheathing materials. Another problem which needs Lo be considered i s that of jamming. Jamming is the wedging of cables within the duct where three or more cables are laying side by side in a flat plane. This situation can easily lead to excessive tension being applied to the cable, hence damaging it. This condition is most likely t o occur when pulling cables around bends and can be avoided by the careful selection of cable fill for a particular size of conduit. There is another potential source of installation damage to cables which is specific to ducted runs, if more than one cable is to be routed in a given duct, then they should all be installed at the same time. Additional cables are never installed over existing ones because the winch wire used to pull the cable can easily cause cut-through damage to the sheaths of th e original cables. It has been pointed out in the previous section on cable support steelwork, that the CEGB favours the use of cantilever type cable support arrangements. When cables are being installed, it allows them to be pulled from the drum, laid alongside their support steelwork and then lifted into place. This will in turn
reduce the loads to which the cables are subjected during installation. Where the use of trapeze type cable support structures is unavoidable (usually only for certain seismic applications where additional rigidity is required), installation is greatly complicated by the need to thread cables through the supports. When the cable is being pulled from the drum, it is important to ensure that the drum itself is conveniently placed, so that the cable does not have to negotiate any unnecessary bends. The drum itself should be supported on a freely turning axle with the cable being removed over the top of the drum. The cables must never be removed from the drum by rolling the drum along on its flanges, since the arc length at the drum flange will be greater than that of the cable on the drum. Attempting to do this will lead to the cable being used to skid the drum round on its flanges. The CEGB normally uses two basic pulling techniques, hand pulling and winch (or nose) pulling. The former is self-explanatory. Its advantage is that cables are unlikely to be subjected to excessive pulling tensions. The drawback is of course, that the technique is highly labour intensive and hence expensive. Good access is also essential for the whole of the route length, requiring complicated and expensive scaffold ing. Obviously, the larger the cable, the more difficult it will be to hand pull it. In the alternative method, the pulling force is pro vided by a motorised winch. Here, a winch rope (usually of the plastic coated steel type) is connected to the
520
ANN
Cable installation practices the cable using a flexible stocking, of the type and the winch wire wound-in by on in Fig 6.98, This puffing method obviously requires Inotor. labour during the pull, although it may be jirecr to set up a number of sheaves and rollers he route prior to pulling. For this reason, most i would be gained from using this method a number or cables are to be pulled along the rouie. If a winch rope is pulled across a cable considerable damage due to friction a can c lliSC :rnahrough, even if that winch rope is plastic coated L, [herefore, the utmost care must be taken when cables onto steelwork where other cables have „ Ain , been installed. rcJJ
of
,v■HE a,cEps coNsisT!NG QE Two ,-,..„-;Ns OF w,RE WITH ENDS TWISTED T.TDGE I OR TC sEcuRE THE SONO IN TIGHTENS UNDER -.TOSTION L.NT'L ^ . 3 STRAiN 71-,E
,
1 10000.**NA :iw c_
c.c.clo
AP L■CA. - ON OF BOND TO ENO DE CABLE
NR. 6.98 Method of attaching pulling bond to
multipair cables
It is also important to ensure that a non-stretch ,inch rope is used, as this will remove the tendency 'or a succession of impulse loads to be applied to the ,able during pulling. Since a motor is providing the pulling power, there al,o more potential for applying excessive load to 'he cable using this pulling technique. It is essential :icrel'ore that the winch operator is in close cornFrItinication with other members of the pulling gang ,',Itioned along the run, who can warn him if the cable ecoilies snagged or caught. When using this installa'ion method, it is also necessary to monitor the load placed on the cable during the pull for comparison the maximum allowable pull tension for the cable. I is is usually achieved by means of a dynamometer to the winch rope. \nother method of ensuring that excessive loads %ire not applied to the cable, is by placing a shear device tu e Pulling wire which will fail at a predetermined !enNion. The CEGB does not favour the use of such .1,2\ ices as they can cause a safety hazard, due to whipif they fail suddenly. Finally, as an additional precaution against damaged ublc being used in service, a 1.5 metre length is always trom the nose of the cable following the pull. More sophisticated cable pulling methods also exist, ‘tich as motorised rollers and running bond techniques. (hese are discussed briefly as follows. ,
,
Motorised rollers The motorised roller basically consists of an electrically-driven rubber-tyred roller with a spring-loaded bearer roller to create a friction grip. The degree of spring loading is variable and this determines how much tensile load can be applied to the cable before slip occurs. On a typical cable route, a number of these motorised rollers would be installed prior to cable installation, mainly on either side of bends, and these would be used in conjunction with standard non-driven rollers and sheaves. These motorised rollers are all controlled from a central panel, all being simultaneously switched. During the cable pull, personnel are required at all bends (as a minimum), to guide the cable through the rollers. It is important that such personnel are in contact with the operator at the central control panel to advise him of any problems occurring with the pull, so that the driven rollers can be turned off to prevent damage to cable sheaths by continual slippage. The motorised roller technique has the following advantages: • It significantly reduces the tensile loads placed on the cable during installation and hence damage potential. • It offers the potential for pulling cables through very complicated routes without the risk of applying too much load to the cable. The tensile load applied
to the cable only amounts to that required to pull the cable from the previous motorised roller. • There is, in theory, no limit to the length of an individual cable pull. The disadvantages with this technique are: • The setting up of the rollers, including a complex alignment process, is time consuming and expensive. • Generally individual cables (or at best, two or three cables of the same diameter), only can be pulled through motorised rollers in one pass. After each pull, individual cables would therefore have to be removed from the rollers before another cable can be pulled through the same roller set-up. • The space available between individual cable carriers is limited and may physically prevent the use of these motorised rollers. • The pulling equipment is much more sophisticated than that required for nose pulling and is therefore more expensive. Running bond techniques The principle of the running bond cable pulling tech-
nique is shown in Fig 6.99. The technique is widely used and has been developed by the distribution side of the electricity supply industry for the installation of large, delicate, high voltage cables in trenches. 521
11•""" Cabling
Chapter 6 Amy,
STEEL DRUM
30 LID
CAB.LE LiN TIED
CABLE 7 ED
SNATCH BLOCK
112111111141121111111B1111111111111 -1ENN
lartatErsitliEMESEMEMIErriptii CABLE RE 7 ED
am smi or NI lim Sim
DEEP WALL LADDER RACK
rom Ulm Um • ii CABLE UNTIED
Elm
80^.0
SNATCH BLOCK
MIT,':•-, 0 :4,1atommummusse MAI itlitlISMBEIMIE CABLE RE-TEED
METHOD OF 1 7YiNG 70 CABLE
FIG. 6.99 Running bond technique
A steel bondwire, of at least twice the length of the cable section length over which pulling is to be carried out, is run-out through the whole section length over cable rollers positioned along the line which the cable is to follow. As with nose pulling techniques, those rollers should be installed at sufficient frequency to prevent the cable from dragging along the support steelwork. The cable is then tied to the bond wire at 2 metre intervals along its entire length, increasing the frequency of ties if the cable is to be installed on a steep incline or through vertical run sections. At each change of direction during the pull, the bond ties are released and the cable is taken round the bend using separate skid plates and rollers with the bond wire passing through a separate snatch block. After each bend, the bond ties are replaced. Whilst traversing each bend, the nose of the cable is guided over the corner rollers to ensure that a positive tension is maintained to prevent build up of slack at the bend. The advantages of this pulling technique are similar to those of the motorised roller technique, namely: • The reduction of tensile load applied to the cable. • The potential to pull through complex routes. • The potential to pull through very long routes. 522
The disadvantages again revolve around the time and effort required to set up the rollers and snatch blocks prior to pulling. The tying and untying of the bond wires at each bend is also very time consuming and labour intensive. In general, the cable support steelwork design and layout philosophy used by the CEGB, in particular the use of cantilever supports, means that the motorised roller and running bond cable pulling techniques are not necessary. They do, however, have a potential for application to the problem of pulling cables through successive trapeze type supports.
8 Cable performance under fire conditions This section deals with cable performance under fire conditions with respect to flame spread and fume emissions, and with the tests used to evaluate these factors. Whilst the burning characteristics with respect (0 flame spread and fume emissions are controlled, such cables may not necessarily be designed to continue functioning under fire conditions. Where circuit integrity is required, then short-time fireproof (STEP) cables as described in Section 3.7 of this chapter must be used.
Cable performance under fire conditions Fires started by faults within cables are rare, altheoretically possible if incorrect electrical pro: i s a pplied. However, because of their service cuon tc ion, cables become involved in fires caused and i . uoct ,,,Jled by other sources, e.g., oil and rubbish. There rc a number of serious cable fires in the 1960s and ,: c 1970s which demonstrated a need for a close ainination of fire protection policies. The majority :hese fires involved PVC cables, although some also or synthetic rubbers such as ethylene propylene (E PR) and chlorosulphonated polyethelene rubuhb examination of these serious cable fires b cr (CSP). An following major conclusions: re‘eaIed the ‘‘. here large quantities of cables were involved, the • could propagate along both horizontal and vertire alarming speed (10 metres/ tical cable routes at an rninute).
•
Large quantities of dense smoke might be evolved hich would hamper fire fighting operations.
fumes could be pro• Large quantities of corrosive damage building materials, switchwhich might duced gear and electronic equipment. ts,,:h the cable insulation and sheathing materials availJble in the early 1970s, it was not possible to produce new designs of cables that would reduce all three of h cs e risks. As far as power stations are concerned, because of the large numbers of cables involved, it
.; i, decided to concentrate on reduced fire propagation characteristics. Until these serious fires occurred during the late i960s, PVC had been considered to' be a fire retardant material. This belief was founded on the ability of a single cable to pass the type of flame test detailed in the
lollowing subsection. This test method was originally ..f oised to assess cables having fibrous coatings impregnated with so called flame retardant paints. When it was ,
ubsequently found that PVC sheathed cables passed uch a test this earned PVC the description of flame retardant. Research after these major fires showed that, hilst a single PVC cable would not burn when the , ource of ignition was removed, if sufficient of these ihles were grouped together then there was a critical mu.ss above which propagation could occur. However, no precise figure of PVC critical mass is possible hccause this varies with the formulation of the PVC ompound and the cable installation arrangement, but i) generally accepted to be in the order of 2-3 kg per metre. it was therefore clear that the earlier practice of .1 ssing fire performance by testing a single cable was inadequate and a new test had to be devised in which ,:ahles were fire tested in a density and formation representative of the actual installation. Details of these rckluced fire propagation tests are given in Section 8.2 of this chapter. Cables to meet this new standard were constructed mainly from specially formulated PVC , ompounds which still liberated considerable quantities ,
,
of hydrochloric acid gas (HCI) and smoke under fire conditions. However by restricting propagation, the quantity of cable insulating material involved in the fire is reduced and thus the volume of combustion products. The quantity of smoke and acid that could be liberated is still sufficient to cause considerable damage and therefore all major cable routes need to be enclosed and protected as discussed in Section 2 of this chapter. Compound developments during the early 1980s has offered the prospect of cables which, not only have reduced fire propagation characteristics, but also reduced coloured smoke and corrosive gas emissions. Such cables are generally classified as limited fire hazard. Test methods have been recently developed (1988) to assess smoke, corrosive and toxic emissions; the general principles and background to these have been included in this section for completeness. 8.1 Tests on a single cable or wire Fire tests on single cables or wires are specified to BS4066: Part 1 (IEC 332: Part 1). In this test, the wire or cable is clamped vertically and a bunsen or similar burner is arranged at 45° to the axis of the wire as shown in Fig 6.100. For large cables, two burners are used. The flame is applied to the test sample for a set time and after its removal the sample is left to burn until it self-extinguishes. The amount of uncharred material remaining at the top of the sample is then measured and compared with the acceptance criteria. BS4066: Part 1 is not suitable for wires having a cross-sectional area of 0.5 mm 2 or smaller because the flame is sufficiently harsh to burn through the conductor. A new specification has therefore been prepared for these small wires which employs a smaller burner and this is expected to be published in due course as IEC 332: Part 2. The fire propagation performance of cables is now assessed as described in the following Section 8.2. The type of tests on single samples described here are therefore of greatest value in assessing the fire performance of cores of cables, particularly control cables, and for panel wiring. 8.2 Cable installations having reduced fire propagation During the early 1970s, test methods were developed to assess the fire performance of bunched cables and this culminated in the issue of CEGB Standard 099905 (GDCD Standard 21) — 'Cable installations having reduced fire propagation'. Since it was realised that propagation was dependent on both the mass of cables and also their configuration, the first step in producing this standard was to define standard installation configurations. For type approval purposes, four categories of cable together with their installation conditions were defined as follows: 523
Cabling
Chapter 6
-
a
-
a
A
- 2Snr,
SAMPLE
55cr
SECTIONAL VIEW OF A-A
NON-METALLIC BASE
FIG. 6.100 Test on a single cable or wire
• Category 1 - single core cables tested in spaced formation. • Category 2 .- multicore power cables 16 mm 2 arid above tested in spaced formation. • Category 3 - multicore control cables and small power cables up to and including 16 mm 2 tested in touching formation. • Category 4 - multipair control and instrumentation cables tested in touching formation. All categories were tested with a non-metallic mass of 10 kg/ni. The test rig specified in the first issue of GDCD Standard 21 was based on the Italian CESI laboratory test rig in Milan, the general arrangement being shown in Fig 6.101. The test method consists of mounting cables in a vertical arrangement within a chimney to produce an onerous condition. The cables are heated at the base, using electrical hot plates, with a minimum temperature of 600 ° C and pilot flames are provided to ignite flammable gases that are driven off. Once the cables have ignited they are left to burn and, after one hour, if they have not self-extinguished they are manually extinguished. The test is considered satisfactory if the traces of charred damage on the cables do not extend more than 1.5 rn above the hotplates. All 524
test rigs used must be proved by testing untreated PVC cables to ensure that propagation occurs. In 1982, EEC Publication 332: Part 3 'Tests on bunched wires or cables' was issued. This specifies a test similar to the first issue of GDCD Standard 21, the major differences being that the IEC specifies a gas burner instead of electric hot plates and in addition the acceptance criteria is increased from 1.5 m to 2.5 m. The general arrangement of this test rig is shown in Eig 6.102. The IEC burner is of the ribbon propane-gas type with a fuel input rate of 73.7 106 x J/h (70000 BtU/h). The EEC allows tests at 1.5 L/m, 3.5 L/m and 7 L/m which equate to approximately 2.5 kg/rn, 5 kg/rn and 10 kg/rn using a typical density for the cable combustible materials. A test rig complying with IEC 332: Part 3 had been built in the UK at Queen Mary College Industrial Research Limited and the CEGB evaluated this against the existing GDCD Standard 21 protocol during 1982. Tests were carried out at 10 kg/rn on at least one cable in each of the four GDCD Standard 21 Categories. In addition, an untreated PVC cable was tested to ensure that the rig was capable of producing propagating fires. These tests demonstrated that the EEC test rig could be used as an acceptable substitute for tests to GDCP Standard 21; the test rig was therefore adopted for cable constructions containing PVC materials. Because 01 the size and complexity of power station installatioflS
Cable performance under fire conditions
SMOKE OUTLET
FLUE '/ET
THERMOCOUPLES
STEEL LADDER RACK
_
TEST CABLES APERTURE
tat GENERAL ARRANGEMENT
GAS BURNERS
REMOVABLE ELECTRIC FURNACE CONSISTING OF RADIANT PANELS IN FRONT OF AND BEHIND THE TEST CABLES
6.101 Reduced propagation test rig (electric hotplates)
:,;,iitional requirements beyond the IEC test - method .pecified to reduce the risk of fires propagating. Plc maximum density of cables that the IEC specifies ID kg/m which is the same as GDCD Standard 21, 1 , - Lle 1. This generally results in an economic arrangecnc Category 1 and 2 cables which are installed ed to maintain their current rating. However, for .i cuories 3 and 4, the cables are installed touching .a1,1 a restriction to 10 kg/m of non-metallic material in the cable tray being under-loaded as far as ra,c and weight considerations are concerned. For .1!cgories 3 and 4, tests may therefore now be specified 2 ) f kg/m or higher. A further requirement is that the test, penetration to the conductor should be Iltned (i.e., the conductor insulation should be con.. med or degraded to ash). If this is not achieved then • Qables are retested with a burner having a larger ' 4 output. The reason for this is that it is possible
(b) TYPICAL TEST RESULT
FIG. 6.102 Reduced propagation test rig
(gas burner)
to design a cable with suitable heat barrier tapes to pass the test with a 70 000 Btu/h burner. However, 525
111•"" Cabling when this cable is subjected to a greater heat source, as may be the case in a real fire situation, then the barrier tapes may break down allowing the more flammable insulation within to be exposed and propagation can occur. By trying to obtain penetration to the conductor during the test this risk is reduced. During the 1970s special PVC compounds were formulated to enable cables to be constructed to pass these propagation tests. This was achieved by the use of various additives which did not generally affect the mechanical performance of the PVC. The most commonly used additive today is antimony trioxide which acts together with the chlorine in PVC to suppress the flames. The use of PVC produces cables that have high smoke and acid emissions due to the halogens in the material. A requirement for low smoke and acid emission requires the use of non-halogenated materials, but means that the halogen gases are not available to interrupt the combustion process. One of the polymers that is becoming popular for limited fire hazard (LFH) cables is ethylene/vinyl acetate (EVA) and, to give this reduced propagation performance, it can be heavily filled with aluminium hydroxide (alumina trihydrate). This filler contains about 35% water which is released at temperatures above 200 ° C with the absorption of heat. The steam produced also dilutes the flammable gases given-off from the polymer. Whilst Category 1 and 2 LFH cables were found to behave in a similar manner to PVC cables, when testing non-PVC Category 3 and 4 cable designs (which are required to be mounted in a close touching formation) it was found that they behaved i,n a manner different
to PVC cables. With PVC cables there is a greater tendency for propagation with increasing mass. This was not apparent with new limited fire hazard designs. It was noted that cables nearest the burner became involved in the fire but any cables in the second or subsequent further-removed rows were substantially unaffected. With PVC cable designs it had been normal for all cables at burner level to become involved in the fire. In service installations however, cables are not normally tightly held in regimented rows as specified for this fire test. In a cable riser, the cables are cleated in small bundles having a maximum diameter of 75 mm, whilst on horizontal runs the mix of different sizes of cables gives a natural break-up from the close array that may be attained with cables of one size. Tests were therefore conducted with cables fixed to the ladder in bundles approximately 60 mm wide with 20 mm between bundles. When tested in this manner, it was found that cables tended to propagate fire more readily and this tendency increased with the mass being tested. Indeed, tests were carried out with cables mounted in blocks over the range from 2.5 kg/m up to 30 kg/m of non-metallic material and consistent results were obtained throughout. In summary, For Categories 3 and 4, a close regimented touching array as specified by IEC 332, Part 3, 526
Chapter 6 is considered acceptable for PVC, since normally a ll non-metallic material is involved during test at bur ner level. However, this method of mounting is not typi . cal of an actual service condition and for new cable designs it may give inconsistent results. The CEGB Standard for li mited fire hazard cables therefore r e . quires Category 3 and 4 cables to be tested in disc rete bundles. In practice, the number of cables that can be placed on a cable tray is limited by the space available on th e cable supporting steelwork or the maximum weight it can carry. For Categories 1 and 2, where the cables are installed in spaced formation to achieve adequate current rating, space is the limiting factor and the maximum non metallic mass that can he usefully used is 10 kg/m. For Categories 3 and 4, where the cables are bunched, the maximum non metallic mass is controlled by the maximum cable dead-load that the steel. work can support. As discussed in Section 7 of this chapter, GDCD Standard 197 600 mm wide ladder racks are designed to carry a dead-load of 50 kg/rn. This means that a test with a non-metallic mass of 20 kg/m is adequate for Categories 3 and 4 to match the steelwork design. -
-
8.3 Oxygen index tests The oxygen index (01) of a material is defined as the
minimum concentration of oxygen, expressed as a percentage by volume, in a mixture of oxygen and nitrogen that will just support combustion of material under defined conditions. A suitable test method is given in Appendix A of BS4066: Part 3: 1986. In this test a sample of material is mounted vertically in a glass chimney through which a known mixture of oxygen and nitrogen is passed. The top of the sample is ignited and its behaviour noted to see if it burns beyond a set distance or if it self-extinguishes within a prescribed ti me. The oxygen/nitrogen ratio is adjusted until the material under test just supports combustion, the concentration of oxygen as a percentage by volume is then recorded as the OI of the material. The 01 of a typical untreated PVC will be of the order of 25%, whilst a treated PVC used in reduced propagation cables may have an oxygen index in the range 30 to 40%. However, it must not be assumed that a compound with a higher 01 will automatically produce a cable with greater resistance to fire propaga. tion. Two materials having the same OI may behave completely differently depending on the polymer type and the additives used to give flame retardence. It must also be borne in mind that the test is carried out at ambient temperature and also that the flame is re quired to burn downwards like a candle; the test conditions are therefore not representative of a typical real fire situation. For these reasons an oxygen index test must not be considered as a substitute for the proPa' gation tests described in the previous Section 8.2.
Cable performance under fire conditions r this oxygen index test is very reproducible n excellent method for quality control of 0,1 forms aused in reduced propagation cable systems. „ ia rou-nds d previously, a high 01 does not necessariate a 1,etter flame propagation performance and, \ ',:, [ . d for routine OA tests, it is necessary to conand maximum 01 levels. This bot h the minimum a,:hio.ed by measuring the 01 of materials of L, c ,albjected to reduced propagation type tests ded in the previous section. A positive and negative ,:, L b e rLince (in the order of ± 1.5%) is then agreed with •,,,, manufacturer for routine tests. It should be noted apply this principle the absolute OI must be ro ireci. Therefore, when using Appendix A of BS4066 .re testing of power station cables, it is im•o r routine ,,,,riant :hat the complete test in Section A8 is specified than the abbreviated test in Section A10 which 111% checks for a minimum. In summary, 01 tests are to check whether a material has changed rather 'Lin to see if it meets a minimum 01 requirement. ariation of this type of test which is gaining pu11r1ty is to measure the temperature index of the : •„i:crial. The apparatus used for this test is similar to ti,e(1 for oxygen index with the addition of heaters ijl rul the glass chimney. Both the oxygen/nitrogen .rou and test temperatures are varied to enable a plot of the type shown in Fig 6.103 to be prepared. The , ,mperature index of the materials is taken to be the .,. amcrature at which the sample just supports cornjon with an oxygen concentration in nitrogen of :110 Whilst this type of test arguably gives greater ',formation on the material than a plain oxygen index a must be remembered that it is still only a test ci materials. Like the OI test it cannot be considered , albstitute for full scale propagation tests, since it is ciilccn that both the quantity of cable and the cable •. , ari pration affect flame spread. With present teche
35
• ;EN
25
!'
100
204
250
FIG. 6.103 Graph showing temperature index
300
niques, the temperature index test is time consuming and is less reproducible than an 01 test because of sample deformation at higher temperatures. It is not therefore considered practical as a routine test. It is however considered by many manufacturers to be a useful aid to material assessment.
8.4 Smoke tests 8.4.1 Test methods There are two common methods of quantifying smoke emissions: • Measurement of light obscuration through smoke. • Weighing of smoke particles after trapping them in a filter. Considering these methods, the weighing of smoke particles ignores the effect that particle size has on visibility, i.e., a lot of small particles will reduce visibility more than a fewer number of large particles for the same total weight. Measurement of light obscuration is therefore considered more meaningful where it is desired to obtain a degree of correlation between tests and the visibility of, say, exit signs in a real fire situation. Early investigations into smoke emission were carried out using small samples of cable materials in bench top equipment such as the USA National Bureau of Standards (NBS) or the Arapahoe smoke chambers. The NBS is an optical method in which a sample is burnt (either in a flaming or non-flaming mode) in a chamber having a volume of approximately 0.5 m 3 . Light transmission is measured using a photometric system with a vertical path. The Arapahoe is a gravimetric system in which a sample is burnt using a small propane-gas burner and the smoke particles are trapped in a filter and weighed. More recent work has shown that smoke emission is highly dependent on the number of cables involved and their configuration, i.e., spaced or touching formation. The situation is similar to testing for reduced propagation characteristics where tests on materials or single cables are inadequate as type tests. These bench-top tests are now therefore only recommended for routine tests such as quality control and for the preliminary evaluation of materials. For type tests it is considered essential to carry out large scale tests on a typical cable arrangement. One such large scale test method which was developed by the London Transport Executive (LTE) in the early 1970s is the 3-metre cube and this has now gained international popularity. The test equipment which is shown in Fig 6.104 consists of a cube of 3-metre side and normally constructed from metal sheet. A door containing an inspection window is provided in one side for access purposes. Small windows are provided in opposite sides of the cube to enable a light 527
Cabling
Chapter 6
LADDER FOR MOON TWO CABLE SAMPLES I
/ /
• 3AS BURNER
SOT RCS
DETECTOR
_ORAL:Or-if SCREEN
,NINDOW
WINDOW
Jr,
FAN
AIRFLOW
•
TiEiGHT OF ENCLOSURE = 3,, ACCESS DOOR ,VITH OBSERVATION WINDOW
FIG. 6.104 3-metre smoke cube
source and photoelectric cell assembly to be mounted externally, so that the attenuation of light with increasing smoke density can be measured. The photocell is designed to have a response close to that of the human eye. A fan is provided to mix the smoke and give reproducible results. Since a large number of manufacturers and test authorities have constructed this test equipment, there is clearly a need to ensure they all have similar characteristics. This can be achieved by burning known ratios of toluene/alcohol in the cube and checking the light attenuation against reference values. The 3-metre cube is now a well established test equipment that is relatively simple and very practical. Having established suitable test equipment to measure smoke from a representative section of cable installation, we must now consider the fire model. The fire model used by LTE consists of burning a number of cables by placing them in horizontal formation over a fire source consisting of a tray containing I litre of alcohol. The number of cable samples is selected such that the test configuration contains 2-3 kg/m of combustible material which is considered typical of an underground railway installation. However, within a power station, higher densities of cables are involved and a number of routes are vertical; the LTE fire model is therefore not suitable for power stations. Considering power station applications, quite clearly for smoke tests it is desirable to use a vertical array of cable samples known to be the more onerous case. This follows the same principle as for reduced propagation tests. Taking this one step further to be consistent, the same type of fire model should be used for both the reduced propagation and smoke tests (i.e., a vertical ladder with a propane-gas burner fire source). In practice it is not possible to use the identical arrangement for smoke 528
tests because of limitations of the 3-metre cube te st equipment, e.g., the cable quantity subjected to the test has to be limited to avoid smoke saturation i n the cube. Although it is not possible to carry out smoke tests in the 3-metre cube on the largest array of cabli ng used in a power station, it is possible to use a representative sample which is adequate to correlate smoke emission with the effects of propagation. The fire model selected for type tests is shown in Fig 6.105 and consists of cable samples 2 metres long, wired to a vertical ladder. The number of cable sampl es is selected to give a loading of 5 kg/m of non-met a lli c material and the cables are mounted in the same formation as detailed for reduced propagation in Section 8.2 of this chapter, i.e., power cables spaced and control cables bunched. It is important to note that cable formation is a dominant factor in smoke production and that variations in cable spacing can significantly affect results. The fire source itself consists of the same propane-gas ribbon burner and flow rates as used for the propagation test. The test regime consists of apply. ing the fire source for a period of 25 minutes, after which it is extinguished and the samples are left burn or smoulder until maximum smoke productioi: has been achieved. By this method both flaming and non-flaming modes can be assessed.
CABLE SAMPLES 2m LONG
LAODER
GAS BURNER
II
FIG. 6.105 Cable sample arrangement for smoke test
During the test, the intensity of the light received by the photocell is monitored on a chart recorder as a measure of transmittance. The recorded light transmittance can be converted to absorbance using the formula:
Cable performance under fire conditions 1
A, = login 0/ 1- t kl here IC) t
where D = visibility distance
K = parameter dependent on light level and type of exit sign
initial luminous intensity -- intensity of light beam through smoke
From Equations (6.8) and (6.9):
ormal to present the results as standard absor1, n A„ by the formula ;,, i ,
D=
A,) -= A, x -.s. volume of test chamber, m
KY
(6,10)
A0 n
Now the factor 'n' must relate the quantity of cable material tested to that contained in the power station installation. It is suggested that the smoke test be car-
3
t' = optical path length, m
,is hen defined as the absorbance produced across faces of 'a 1-metre cube when the test installation he !, burnt under the given conditions. The calculation for A o ignores the effect of any deposited on the windows of the optical system. ‘riloke flis is because experience has shown that the absorb.111,:e associated with this deposition on the windows ,, ;mall compared to the absorbance associated with he smoke in the cube, and negligible error is caused i2noring this factor. Where it is wished to take :MN factor into account, the absorbance associated with Jcposition on the windows can be measured after clearmoke from the cube and the appropriate correc!i ons made. Clearly A 0 can be calculated at any time during ;he test but the most significant measurements are „on,idered to be at the end of the test flame appli-aion period, A, (ON), and the maximum after the :lame is extinguished, A 0 (OFF). Quite clearly the inft,t critical factor is the total smoke generation drid since this is achieved during the A o (OFF) period, ,hould be used for the acceptance criteria. A typical !e,i requirement would be that A, (OFF) should not ,A,eed 10.
84.2 Use of test information I la ,,ing defined a test method we can now try to re.i e information gained to what would happen Ii power station locations under fire conditions. One 1mhod of achieving this is as follows: The 'expected absorbance' in a particular location .
ried out on an array containing 5 kg/m of non-metallic combustible material. Therefore, assuming a linear relationship: n=
installed mass
installed mass
test mass
5
Typical values for the parameter K are given in Table
6.23. These parameters are based on experiments carried out in a 3-metre cube, using a random sample of observers to assess the visability of typical signs over a range of distances through a known density of smoke. TABLE 6.23 Typical values for the parameter K
Lighting
Value of K
Self-illuminated signs
3.0 — 3.5
Reflecting signs in well lit areas
1.5
Reflecting signs in poorly lit areas
1,0
As an example, consider a cable flat 2 m wide by 2 m high and 50 m long. Using a test acceptance criterion of A 0 (OFF) = 10 and assuming one cable tray carrying a non-metallic combustible cable mass of 10 kg/m, for self-illuminated signs the visibility would be: D=
kV Aon
–
3 x 2 x 2 x 50
– 30 m
10 x 10/5
• ,q1N.en by:
A, = A o n/V
(6.8)
' h ere A0 --: absorbance across the faces of a 1 m
The results obtained by this process should only be used for guidance since the process assumes an even dispersion of smoke particles and ignores any irritant affect that smoke may have on the eyes.
cube found from test V
n
dispersal volume,
M3
8.5 Corrosive gas emissions
factor depending on quantity of cable involved A, = — D
(6.9)
At present, bench-top tests on samples of materials
taken from cables are considered the most practical method of assessing corrosive gas emissions. The most commonly used of these bench-top tests is that specified in IEC 754. This test method requires 529
Cabling
Chapter 6
that approximately one gram of material is pyrolysed in a combustion tube using an electric furnace. Ramp heating is used with a maximum temperature of 800 ° C and the resultant gases are analysed by titration methods. Hydrogen chloride and hydrogen bromide are assessed as hydrogen chloride and the limit of sensitivity of this method is 0.5%. The difficulty with this test method is that it only assesses two of the halogen gases and, whilst hydrogen chloride may be potentially the most aggressive, other corrosive gases cannot be ignored. Another drawback with this method is that the limit of detection is 0.5% and may not be adequate for recent developments in low fire risk cables. The CEGB has therefore developed a test method which monitors pH and conductivity which can detect all acid species. A diagrammatic arrangement of the test apparatus is given in Fig 6.106. The combustion arrangement is similar to EEC 754 in that the sample is pyrolysed in a combustion tube using an electric furnace and ramp heating up to 800 ° C. A sample size of one gram is used and the combustion products are drawn through distilled water of which the pH and conductivity is measured. Since hydrogen chloride is
of particular concern, a sensitive chloride ion electrode is included which can monitor to a level of 0.05%. Experimental work has been carried out for the CEGR to assess the corrosive effects of the more commo n acid gas species on items such as printed circuit boards and relay contacts. From this work it is possible to judg e the maximum concentration of gas in parts per milli on (PPM) that is tolerable from a corrosion aspect. Using this information, together with a knowledge of th e quantity of cable material likely to be consumed in a fire and the station volume in which it may be released, it is possible to predict pH acceptance levels for the test method discussed.
8.6 Toxic gas emissions At present, bench-top tests on samples of material taken from cables are considered to be the most practical way of assessing toxic gas emissions. There are several such tests available but the most established in this country is that defined in the Ministry of Defence specification NES 713. This test procedure has therefore been used as a basis for CEGB assessment of toxic gas emissions.
OR!ED
THEnmo-
COUPLES COMBUSTION TUBE
_17
pH VHION
METER
1
CELL WITH CP TO FIVE PROBES OE-IONISED H20 MAGNETIC STIRRER
Fm. 6.106 Corrosive gas emission test equipment
530
Cable accessories test method consists of . burning a four irin a sealed chamber having a volume of 1 e CEG , ::: , a a l p metre. The chamber is constructed from a 1 (typically polypropylene or polycari il ai [‘ei rni ,a a tranyarent access door in wohni eside. ch the :„Iritille is burnt using a gas burner in 1‘.. ith air. A fan is used to ensure rapid v■ :1 , , ',remixed f products of combustion with the air in the o combustion products are drawn :bcr. Samples of the enclosure through gas detection tubes. o t [he tes: as detection tubes consist of a glass tube filled [ which change colour when they react with ,tals ..:Iccied gas type. A selection of gas detection tubes to assess the toxic gas emissions that are likely obtained from cable insulating materials. ()\icity index can be calculated from the measured ncentrations using IDLH values. The immediate life and health (IDLH) value, as defined j.til2er to the NIOSH/OSHA 'Guide to chemical hazards', r, a maximum level from which one could ,.„re %satin 30 minutes without any escape-impairing :liriorns or any irreversible effects on health.
EARTH BOLT
PLASTIC WASHER
ARMOUR CLAMP
METAL EXTENSION TUBE
CABLE ARMOUR
OUTER NE;SPR ENE SEAL
0 KNU
ASSOCiATEO ENCLOSURE OR GLANO PLATE
PLASTIC NSULATECI \ BUSH
OU 7 E. SEAL Vu
NEOPRENE FACE SEAL
iNSULATED SECT:ON
9 Cable accessories
9.1 g1.1
Cable glands Background to gland design
elands are used to terminate the outer finishes ables (i.e., inner sheath, armour and outer sheath) to take the insulated conductors through into the •.j uiptucnt. The gland therefore locates the cable at the .,;inpment and is required to form a moisture seal to ..,,t11 the cable and the equipment. Glands also provide iieans of making connections to the armour for rig when required. Where connections to earth are .,itlircd, it is important that the gland is fitted with an !cgal earth lug so that a bond can be installed to •.kc the fault current direct to the earth bar. Without provision the fault current would have to flow to 1,ia the less secure route of gland threads, gland H.:!c securing bolts and equipment casing. Hie requirements for cable glands are specified (ii)CD Standard 190: 'Insulated mechanical cable :.trids'. These have been developed as replacements r the traditional all-metal gland designs which are pc,:itied in BS6I21: 'Specification for mechanical ...111J5 Part I — metallic glands'. Insulated glands the cable armour to be isolated from the gland ;'.ate and hence earth. Typical arrangements of insu•kd glands are shown in Fig 6.107. Insulated glands with GDCD Standard 190 must incorporate following features and offer certain advantages cr metallic glands to BS6121, Part 1: • Insulated glands allow single-point bonding of single-eore cables to prevent armour circulating currents and hence permit current rating to be maximised. ,
,
FIG.
6.107 Typical arrangements of insulated cable glands
• Insulated glands allow single-point bonding of control cables to prevent circulating or fault currents flowing in the armour and hence reduce the risk of interference in control and instrumentation circuits. • Insulated glands allow cable armour to be isolated from earth to enable cable outer sheath integrity to be tested. • An integral earth lug is specified to provide an adequately tested means of connecting the cable armour to earth. • GDCD Standard 190 requires that all glands for use on power cables are subjected to short-circuit tests. • A screen terminator can be provided, as shown in Fig 6.108, to allow the copper tape screen of 11 kV cables to be electrically connected to the cable armour. • GDCD Standard 190 requires glands to accept a wider range of cable sizes. 9.1.2 Gland construction
GDCD Standard 190 covers a range of glands which are identified by 'Class Number according to armour type and gland configuration, i.e., whether bonding connectors or screen terminators are required. The armour 531
PIP
Cabling
Chapter 6
OUTEP 'SEAL ASSE . ,! BLY
'NSuLA'ED PUSH
mETAL EX TENSiON r eE NITH .ICOSAL SCREE4 TERki ■ NATCR
A R MOUR L O CK
CABLE COPPER NEOPRENE FACE SEAL TAPE SCREEN
LOCK N uT
PLAS7PC SASHEA
JUBILEE CLIP
Fici, 6.108 Insulated gland with copper tape screen terminator for use on 11 kV cables
types covered are aluminium wire, aluminium strip, steel wire and double steel tape. To avoid corrosion problems, for aluminium armour the gland body is constructed from aluminium and for steel armour the gland body is made from brass. The glands include an outer seal, to seal between the gland and the cable outer sheath. A gland plate seal is also provided to seal between the gland and the gland plate. Inner seals, to seal between the cable inner sheath and the gland to prevent moisture entering the cable armour area are not considered necessary, as cable boxes are normally kept in a dry condition. In addition it is essential that compression-type inner seals are not used on cables insulated with materials such as low-density polythene, since this is likely to flow from under the seal during load cycling and reduce the dielectric strength of the cable. Multipair cables, as described in Section 3.6 of this chapter, have a drain wire provided to enable connections to be made to the screen. Whilst insulated terminators can be provided on the gland for this drain wire to be terminated, it is normally more convenient to provide an insulated block of terminals in the equipment to terminate the drain wires for connection to each other, or to earth, as appropriate. The nisulated portion of the gland is designed and tested to withstand 2 kV for I minute. The figure of 2 kV matches the design criteria for rise of potential on single-point bonded cable armours under fault conditions, this figure also being the minimum voltage withstand for cable sheaths. Quite clearly, if gland bodies can rise to voltages of up to 2 kV at the 'floating end' then insulated shrouds must be fitted for personnel safety. Where control cable glands are not bonded to earth these must also be shrouded to protect personnel 532
from transferred potentials. There is no requirement to shroud glands that are bonded to earth and indeed this would he physically difficult because of tj -k: ing connections. With respect to short-circuit tests, it is jud_ . all power cables that could be fitted into gla Iizes of 40 mm and smaller would be fuse prote , and therefore these sizes of glands are tested at of 13.1 kA for 0.1 s. Gland sizes of 50 mm an 'aye .Iled may accept cables that are circuit-breaker and these are tested at a short-circuit level kA for up to 1 s depending on the capability of ,ble armour. Insulated glands for use with wire braid, -dell as on flexible cables, are not required since such cables are normally short and there is no risk of circulating currents. Standard CX glands to B56121 are therefore used for braided cables. 9.1.3 Gland sizing
When sizing cable glands the following factors must be taken into account: • The dimension over the cable inner sheath (under armour) must be smaller than the gland ! - ore. :nust be • The dimension over the cable outer she greater smaller than the fully-opened outer seal than the test mandrel size to ensure an ad _late seal.
• The gland must be selected for the armour Mgt material and size. There is not a large overlap in cable accommodation between gland sizes and therefore gland sizing should be carried out on the cable manufacturers' dimensional
Cable accessories information rather than that obtained from cable stand3rds. For this reason it is normally the responsibility .the cable installation contractor to ensure that the of manufacturer is supplied with all relevant cable idnd prior to manufacture of glands.
Jii
g 1.4
Installation
normal practice to have equipment supplied with bie gland plates that are undrilled. This is 3c h a othe at the time of ordering equipment, the cable '[. c and hence gland size are unknown. It is normally responsibility of the cable contractor to drill the fit the gland to the cable and equipment. ,21 and plate and p 1,
Ciiand plates should be non-ferrous for cable circuit ,,itirvis of 400 A or greater. Cables should be set as far as practicable in their ri aI position before glanding commences. This is to ,pioid differential movement, e.g., between armour and oiner sheath, which could result in an ineffective seal should the cable be moved excessively after glanding. Ii is tiood practice to cleat all cables at a distance of [l o t more than 1 m below the gland to relieve glands dud dand plates of the cable weight and of the stresses up by thermal cycling of the cables. Even after 0 1 ,: s e precautions, it is not considered good practice !0 use top-entry glands on equipment located out of
be bolted to equipment. Alternatively, some manufacturers prefer to produce lugs by forging solid bars. A compression-lug fined to a single-core cable can be seen in Fig 6.116. The lug is applied to the conductor using dies to compress the fitting down onto the conductor. The large mechanical forces required to complete this operation are provided by a hydraulic tool into which the dies are fitted. Although these large mechanical forces tend to break up the tenacious high electrical resistance aluminium oxide film on the conductor and fittings, to produce a good connection it is still imperative that surfaces are adequately prepared. It is therefore required that fittings are factory cleaned by shot blasting with aluminium oxide grit and are then i mmediately dipped in petroleum jelly, or an equivalent covering, to prevent further oxidation. Cable conductors are cleaned with a stainless steel wire brush and immediately coated with petroleum jelly prior to compression. Lugs are available for use on circular stranded, circular solid and shaped solid aluminium conductors. Properly designed compression fittings provide good reproducible results without the skill necessary to produce a soldered connection. To assist in quality control the following facilities are expected:
doors. Finally after installation of the glands has been ,ompleted all nuts should be checked for tightness. It
• Fittings to be marked with manufacturer's name, identification number and appropriate conductor size.
should also be checked that a gap exists between the land body and armour clamp as this gives assurance :hat the armour wires are locked in the clamp.
• The fitting to be marked to show the position at which the compression die is to be applied unless controlled by other means as the tool is applied.
9.2 Power cable conductor terminations
• A crimping code is to be marked during the formation of the crimp so that the crimping die used can be identified.
This section details methods that are used to terminate ;he conductors of power cables and connect them to „Iiiipment. The conductor connection clearly must be ,dpable of carrying the cable full load current without o■ ,:rheating and must be mechanically robust to with-
any short-circuit forces.
The traditional method of using soldered lugs to terminate conductors has now been completely replaced in poker stations by compression or mechanical fittings. One reason for this is that it is a highly skilled job to tKe soldered lugs, particularly on aluminium conduc;ors, and if full penetration of solder between strands 1, not achieved overheating in use can occur. Secondly, , oldered lugs are not recommended for use on polyMerle cables having a designed limiting short-circuit
.omiductor temperature of 250 ° C since solder softens
am this temperature.
9.21 Fittings for aluminium conductors (o
rnpressjonlugs typically consist of an aluminium Ube of a suitable size to fit over the conductor, which Has been squashed at one end to form a palm that can
• The compression operation must not be interrupted until complete and the tool must be designed to prevent this happening other than by deliberate action by the operator. • Hydraulic tools are to be fitted with a pressure relief valve that will operate at the end of the compression operation to show that this is complete. The test requirements for aluminium compression fittings are given in Engineering Recommendation C79 (1972) — 'Type approval tests for connectors and terminations for aluminium conductors of insulated power cables'. A British Standard, BS4579: Part 3: 1979 — 'Mechanical and compression joints in aluminium conductors', is based on Engineering Recommendation C79 and gives similar requirements. The test regime consists of preparing 6 samples and subjecting them to: • Initial resistance measurements. • Short-circuit tests (optional). 533
Cabling • Electrical load cycling test — 2000 cycles with resistances and temperatures measured every 100 cycles. • Tensile test. The test results are analysed to check whether the compression fittings have remained stable throughout the test. Engineering Recommendation C79 was published before the large scale introduction of elastomeric cables; hence the load cycle test temperature of 80°C above ambient and the short-circuit test temperature of 160 ° C are appropriate to the cables commonly in use at that time, i.e., paper or PVC insulation. When dealing with fittings for elastomeric cables (e.g., XLPE or EPR), it is considered appropriate to increase the load cycle test temperature to 90 ° C above ambient and the short-circuit test temperature to 250 ° C. As already stated, the short-circuit tests are optional and the choice depends on whether the fittings are going to be used on circuits protected by HBC fuses. As discussed in Section 4.2.1 of this chapter, multicore power cables are always fuse protected and there is no requirement to carry out short-circuit tests on fittings for shaped aluminium conductors. Single-core cables with stranded aluminium conductors are normally associated with circuit-breaker controlled circuits. Fittings for these must therefore be short-circuit tested. Fittings for circular solid aluminium conductors are associated with earth cables. Earth cables of 150 mm 2 and larger are used to bond plant that is associated with circuitbreakers, so the conductor fittings must be short-circuit tested. Earth cables smaller than 150 mm 2 are used to bond plant protected by HBC fuses and there is no requirement to have short-circuit tests carried out on these sizes of conductor fitting. At the time of writing there is no published British or IEC Standard to control dimensions of conductor fittings. It is therefore left to the user to specify dimensional constraints, which is essential to ensure that clearances and creepage distances are maintained within standard terminal arrangements. British Standard BS5372: 1976 gives requirements for cable terminations for electrical equipment. 9.2.2 Fittings for copper conductors
The construction method for compression fittings for copper conductors is similar to that for aluminium which was discussed in the previous section. Although not mandatory it is normal practice to tin copper fittings. The requirements for tools and dies, and for marking (given in Section 9.2.1 for aluminium fittings) are considered to be equally relevant to copper fittings. Test requirements for copper fittings are given in BS4579: Part 1: 1980 — 'Performance specification for compression joints in electric cable and wire connectors'. This specification requires six specimens to be prepared and subjected to: 534
Chapter 6 • Initial resistance measurement. • 500 load cycles with resistance measurements every 50 cycles. • Final resistance measurement. • Tensile test. It should be noted that, unlike aluminium, the test regime for copper fittings does not include an optio n of short-circuit tests. Experience from short-circuit tests on equipment in which conductor fittings have necessarily been included have demonstrated a need to design fittings to meet these conditions adequately. For fittings to be used on circuit-breaker controlled circuits, it is therefore recommended that short-circuit tests are carried out in a similar manner to that already prescribed for aluminium conductor fittings. A further point to bear in mind is that BS4579: Part 1 limits the fittings to use on conductors having a maximum conductor temperature of 85 ° C. Therefore, where fittings are required for use on elastomeric cables (e.g., XLPE or EPR) which operate at a continuous conductor temperature of 90 ° C, a more onerous test regime is required. In these cases it is recommended that the load cycling be carried out at 90 ° C above ambient as previously proposed for aluminium fittings in Section 9.2;1 of this chapter. In practice, the vast majority of copper power cables used in power stations are small multicore types insulated with PVC and protected by fuses for which the test requirements given in BS4579: Part 1 for conductor fittings are more than adequate. The comments given in the previous Section 9.2.1 regarding conductor lug dimensions and termination accommodation are equally applicable to copper fittings. 9.2.3 Formed terminations
Formed terminations are a means of terminating solid aluminium conductors by squashing the conductor flat and punching a hole through it for the terminal equipment fixing bolt. The operation is carried out using a hydraulic tool and special dies. An arrangement of formed terminations is shown in Fig 6.109. This idea was proposed in the early 1960s (Burki and Sabine, 1963 [221), but it did not gain any immediate popularity possibly because of concerns about the mechanical and electrical integrity of the flattened palm. Formed terminations were reassessed by the Central Electricity Research Laboratories during the early 19705 and considerable effort was devoted to obtaining optimum palm dimensions for mechanical and electrical performance. The advantages of this system are: • The sensitive interface between conductor and compression fitting is eliminated. • The termination length is considerably reduced, relieving space problems in terminal boxes.
Cable accessories
ALTERNATIVE CONDUCTOR POSJTIONS GrtihNG REVERSE ANGLE TO PALM
Flo. 6.109 Formed terminations
• The cost of purchasing and stocking the fittings is eli minated. • The work content and hence the time required to terminate cables is reduced. • One set of dies can cope with different-shaped conductors. irtned terminations are currently suitable for circular 2 or shaped solid aluminium conductors from 35 mm 2 300 mm . It is not possible to use this tech:Nue on conductor sizes smaller than 35 mm 2 , because :here is insufficient conductor material to form a of adequate mechanical integrity. Vultieore cables having shaped solid aluminium 5. nthictors are normally only used for fuse-protected Therefore, since there is not an onerous shortr‘iiit requirement, the palm area and bolt sizes are to give optimum performance at the highest ... , iitinuous conductor operating temperature. Since c ables having circular solid aluminium of less . :ian 150 inm 2 are associated with the bonding of fuse; , 7oiected equipment, the same palm configuration and oicnce) dies can be used. Furth cables having circular solid aluminium conJueiors of 150 mm 2 and larger may be used to bond squipment controlled by circuit-breakers and therefore Yiese are required to have an adequate short-circuit ; - ertormance. Since earth cables do not have to carry •'" appreciable continuous current, the palm area of e formed termination may be reduced in favour of a :nore robust (thicker) palm to meet short-circuit re:iiiirernents. The radius between the palm and the un,irmed conductor is also larger on earth cable formed .;:r ntinations, at the expense of palm length, to give -rtimum short-circuit performance. Figure 6.109 shows ;
the different forms of terminations for use on fuse protected cables and for earth cables of 150 mm 2 and larger. Figure 6.110 shows the type of hydraulic tool head and dies used to produce formed terminations. Formed terminations for use on fuse-protected circuits have been tested to BS4579: Part 3, the requirements of which were discussed in Section 9.2.1 of this chapter. These tests were carried out with the formed terminations bolted to both aluminium and plain copper connection bars. Although there is no requirement to carry out short-circuit tests on terminations protected by HBC fuses, such tests were carried out (to a final conductor temperature of 160 ° C) to give confidence in the system. A large number of the samples that underwent the 2000 load cycles were simultaneously subjected to 100 Hz vibration of approximately 0.5 mm amplitude without ill effect. Earth cable formed terminations which are designed to have good short-circuit performance have been tested successfully to demonstrate their performance at shortcircuit conductor temperatures in excess of 325 ° C. 9.2.4 Bolting terminations to equipment
Care is required in the selection and preparation of joint surfaces, particularly when dealing with aluminium. With aluminium, an oxide immediately forms on its surface and this is both tenacious and insulating by nature, thus requiring special measures to be taken. After suitable preparation, an aluminium surface can be bolted direct to another aluminium surface or to a plain copper surface. Aluminium can also be bolted direct to hot-dipped tinned copper but not to copper that has been electroplated with tin or silver. This restriction is attributed to the inability of soft platings to crack the aluminium oxide. Since it is difficult onsite to ascertain what type of plating has been used, it is recommended that a brass transition washer of appropriate diameter is always used between aluminium and plated copper. The grade of brass used should have a temperature expansion coefficient that is approximately midway between those of copper and aluminium. This helps to reduce differential movement at the interfaces and hence the shearing of contact points. The brass washer surfaces must of course be suitably prepared on site, or prepared and protected at the manufacturer's works. To avoid this complication, it is recommended that aluminium or plain copper termination interfaces are provided in equipment. The preparation of aluminium bar or formed termination palm contact areas, should consist of abrading the surface with a stainless steel wire brush until all visible traces of oxide are removed and the surface presents a matt finish. The surface must then be coated immediately with petroleum jelly to protect it and produce a low resistance joint. Aluminium compression fittings are normally supplied factory cleaned and these only need to be lightly smeared with petroleum jelly on the mating surface. 535
Cabling
Chapter 6
FRONT LOCATOR
PUNCH .OLDER
CA9LF.
cAeLe
CONDUCTOR
OIL
RAM
PocKElmr, R TO COLLECT TERMNAL HOLE SLUGS
FIG. 6.110 Formed termination tool
Plain copper or brass should also be cleaned with a stainless steel wire brush and immediately coated with petroleum jelly. Tinned surfaces need only be cleaned with a degreasing agent before a light coat of petroleum jelly is applied. Copper compression fittings should be supplied and packaged in a clean condition and only need a light coat of petroleum jelly on the mating palm surface. It is important that the wire brush is made from stainless steel and that a separate brush is kept for each type of metal. If a joint is slackened for any reason it is essential that it is completely undone and remade using the appropriate surface preparations. If aluminium is not involved, after suitable surface preparation the joint can be completed using normal diameter washers (to BS4320) between the joint materials and the fastener. With copper joints, the thin copper oxide film on the joint surfaces ruptures relatively easily to give metal-to-metal contact, therefore, the clamping pressure and hence the fastener torque is not critical. 536
Where aluminium is involved, because of the tenacious nature of the surface oxide, it is essential that the clamping pressure is sufficient to rupture the oxide fil m at contact spots so that metal-to-metal contact is formed. These contact points are actually crests or peaks that are formed on the contact surface by the preparation using a stainless steel wire brush. This contact pressure is clearly dependent on the surface area under the clamping washer and on the torque applied to the fastener. Because aluminium creeps under applied pressure and the dimensional change causes a relaxation in clamping load, it is important that the load is applied over as large an area as practicable. For this purpose, large diameter washers having an area complying with BS4320, Table 2, form C are used. These large-diameter washers are of sufficient area to restrict the aluminium creep whilst being small enough to generate sufficient clamping pressure to rupture su 1. face oxides using acceptable fastener torques. Washers complying with BS4320 have insufficient thickness to avoid deformation and this results in a reduction 01
Cable accessories juipine pressure towards their circumference. It is ,licrefore necessary to use either two washers together preferably washers made to the dimensions given „ r ble 6.24. The washers should be cadmium plated Cd.2. i3S I 706, Class , T ,BLE 6.24
hers clumping ulanumurn DFnienstuns !or Was
Norninal ,i f e of bolt
Inside diameter rum
Outside diameter ram
Thickness
).16
6.4
14
2.0
\IS
8.4
21
2.2
1110
10.5
24
2.4
1112
12.8
28
3.0
1116
16.8
34
3.4
1120
21.0
39
3.4
mm
These torques are applicable to nuts and bolts that have been kept free from grease. If grease is accidentally applied to nuts or bolts a higher clamping pressure will be applied which is unlikely to be deleterious to the joint interface. However, there could be a risk of the fastener breaking. Steel bolts should be grade 8.8 manufactured in accordance with BS3692: 1967. Brass bolts should be manufactured from high tensile materials complying with B52874: 1969, material designations C 2114 (hard) or CZ 115 (cold worked). It is essential that torque wrenches are used at site when tightening joints involving aluminium to ensure that the correct clamping pressure is applied. Where joints are formed between dissimilar metals, and these are exposed to damp environmental conditions such as in cable tunnels or basements, it is essential that they are protected. This can be achieved by coating the completed joint with bitumen paint or by the use of a heavy anticorrosive grease. On no account should such greases be used instead of petroleum jelly for the preparation of joint surfaces.
The bolt torque is calculated from the area of the
ensure that the initial interface pressure is to break down the oxide film and produce ,W dcicuuate number of contact spots to pass the renured current without excessive heating. During service :crc will be a reduction in the clamping load because ,:iiiiiiinium creeps under pressure. Secondly, where the material is different from that of the conductors , clamped, there will be differential thermal exkcini n.ion which will lower the interface pressure with ,
A,I.her (0 . fik:ient
cycling. This will be more prevalent with steel than brass bolts because there is a greater dift mace in the coefficient of thermal expansion of steel r;:lati‘e to aluminium than between brass and These load relaxations tend to occur early in cr‘ ice life, leaving a steady residual load. This residual must be sufficient to avoid excessive destruction contact points due to tensile and shear forces from . 1 ie dimensional changes associated with the load re\Jtion. To achieve an acceptable residual load, it t11: ,:essary to apply a higher pre load to steel bolts to brass bolts. Suitable bolt torques are given in 1,1111 6.25. rhernial , iiIts
,
-
-
TABLE 6.25 Recommended bolt torques
Torque,
sr.ud
Grade 8.8 steet studs
Nm Brass studs
7
5
20
10
35
20
50
40
90
90
150
9.3 Conductor terminations for control cables 9.3.1 Crimped conductor terminations
The dimensional and tooling requirements for crimped conductor terminations for copper conductors in the range of 0.28 to 10 mm 2 are currently given in ESI Standard 12-2, Issue 1. This information will be transferred to ESI Standard 50-18 when it is raised to Issue 2, and type test requirements will be added. These crimped conductor fittings are required to be provided in uninsulated and pre-insulated forms. For the preinsulated form, insulation is applied over the conductor barrel during manufacture and this is frequently colour coded to indicate the conductor size range for which the crimp is suitable. Terminations are required to provide insulation support for flexible/stranded conductors of 0.5 mm 2 and below, and for single-strand conductors of 1 mm 2 and below. The forms of termination used are hook, pin, blade, ring and snap-on receptacle, these all being shown in Fig 6.111. Hook type terminations are for use with screw clamp/spring-loaded insertion terminal blocks and may be used 'back to back' where two terminations are required in one terminal. Pin and blade type terminations are for use with insertion type terminals and the blade type only may be used 'back to back' where two terminations are required in one terminal. Ring type terminations are for general use with screw or stud type terminals. Snap-on connectors are for use with tab type terminals having tabs 6.3 mm wide of the form detailed in BS5057: 1973. Type test requirements for these crimped fittings are based on BS4579: Part 1: 1970, with additional requirements for salt and sulphur corrosion tests. Hook 537
Cabling
Cha pte r 6
HOOK
FAST ON
Fic. 6.111 Control cable crimped terminations
type terminations are also subjected to tensile tests to ensure that they can be retained in a spring-loaded insertion terminal block with the terminal clamping screw fully released. The mechanical reliability of snapon terminations is assessed in accordance with Clause 10 of BS5057: 1973. The ring type terminals may also be used to terminate s mall power cables but consideration must be given to the maximum operating temperature, particularly with the pre-insulated type. 9.3.2 Wire wrapped terminations
A wire wrap termination is formed by wrapping the stripped conductor tightly around a sharp cornered terminal to form a sound electrical and mechanical joint without soldering. Such an arrangement is shown in Fig 6.112. General requirements for wire wrap terminations are given in EEC Publication 352. The method is suitable for use with solid single-strand conductors of the type used in multipair cables described in Section 3.6 of this chapter. The conductor size of 1/0.8 mm is relatively large by conventional wire-wrapping standards but is well within the capability of the method. The wire wrap method offers the advantages of a compact, consistent, reliable and fast termination. The type of termination used should be the modified wire wrap connection which wraps a minimum of one half turn of insulation around the post as well as the turns of uninsulated wire that form the electrical connection. This half turn of insulation gives improved vibration characteristics. Wire wrap joints can be produced by stripping the insulated wire for the set distance to give the required number of turns and then using a pre-strip bit. An alternative method is to use 538
Fic. 6.112 Wire wrap termination
a 'cut, strip and wrap' bit which severs the conductor, strips the insulation and wraps the termination in one operation. The 'cut, strip and wrap' technique is faster and hence cheaper than using separate operations to strip and wrap. A typical cut, strip and wrap operation is shown in Fig 6.113. The bit is used in conjunction with a high torque hand-held electrically-operated gun of the type shown. The principle of the method is that the wire is wrapped under a high level of tensile stress. Notches are formed in the wire by the edges of the terminal
WIRE WRAPPING BIT
INSULATION REMOVED
.
r.. ---CABLE CC71E-
1110
WIRE WRAPPING TOO'.
611W
TERMINAL BOARD
FIG. 6.113 Wire wrapping tool operation
Cable accessories
wrapping and these lock the wire in posi wire to remain in tensile stress with the ,!, as L i in compressive stress. The forces set up , rin i ria • oteh area at the terminal corner are such as ,i„.. 1 tigh t corrosive-resistant joint. Indeed rr oJiice a gasn reported 1231 that the stresses involved b ee notch areas are sufficiently large to penetrate :ie and tarnish films and promote cold welding. In it is considered beneficial to have one of t:nned and the most economical way is es , urtac he terminal post rather than the wire. For the f wire being considered (1/0.8 mm) a Minimum o tour turns of bare wire is specified. This means if a four-cornered post is used there will be in order of 16 terminal/wire notches with intimate • contact, which explains why a high degree of rival ,onsistency and reliability is achieved with this type of jri
aim. considering the parameters of the wire being wrapped, if it is required that tensile stresses are quite Llearly in between terminal/wire notches then the wire ., 111 ,1 not he stretched beyond its yield point. To meet '!ii requirement it is recommended that wires of the .i/e being considered have a minimum of 20% elonga:on at break. When using cut, strip and wrap tech,ques the force required to strip the insulation affects n ic %%rapping tension and hence the integrity of the ;tlint. For PVC insulated wires this is not generally a problem, but some low fire risk insulations are harder or show an affinity for copper and, with these, this point must be considered. In extreme cases it may only possible to use separate stripping and wrapping operations. The terminal post itself can take a number of forms as square, oblong, triangular or V-shaped. For performance it is advantageous to have the largest .:Ii mber of contact points (notches) per wrap and from 11 point of view square or oblong terminal posts are s!....sirable. The maximum radius for post corners needs he controlled as this affects the notch depth and !Ln,:e joint performance. To demonstrate the signifi.;ince of this requirement consider the extreme of a q!lare post with large radii, i.e., a circular post, in .thich case there will be no notches, no locked-in stress in the wire and hence no significant elec:1- ical or mechanical performance. The terminal post 111151 be harder than the wire so that the notch is !, , :rned in the latter. Considering these and other factors is recommended that terminals meet the following :guiremen'ts: !
• The edges shall be parallel within 0.05 mm per 10 mm over the entire wrapping length. • The posts shall have 18 mm of %vrappable length. The wrappable length is defined as the length of terminal post that has a full cross-section available for wrapping. • The tip of the post is to be bevelled to facilitate insertion into the wrapping tool. • The spacing of the posts shall be such as to allow access for the wrapping tool when all adjacent posts have been wrapped (minimum 6 mm centres). • The terminal block shall withstand voltages of 2 kV between posts (when wrapped) and 5 kV between post and earth. The wire wrap joint should not be considered permanent as it can be removed by unwinding the wire in the opposite direction to the original wrap. Since the terminal is harder than the wire, a number of wraps (at least 10) can be made on the same post before its edges become sufficiently rounded to reduce joint integrity. However, the wire can only be wrapped once and therefore a previously wrapped section must be cut off prior to re-terminating.
9.4 11 kV terminations As stated in Section 3.1 of this chapter, with 11 kV cables it is necessary to provide semi-conducting screens to control the electric stress within the primary insulation. The core insulation screen cannot simply be cut back and left at the cable end as very high electric stress would occur at that point (see Fig 6.114). Such areas
INSULATION
EOUIPOTENTIAL LINES
,
.
-,
• The post size to be 0.79 mm x 1.57 mm. • ihe post material to be phosphor bronze to BS2870, designation PB102, condition half-hard, electrotinned 0.0127 mm minimum average thickness to BS 1872. • •
CONOLIOTOR
SCREEN
L
FLUX LINES
The maximum radius of post edge shall be 0.075 mm. The maximum edge burr shall be 0.05 mm.
FIG. 6.114 11 kV cable screen termination without
stress control
539
Cabling
Chapter 6
of high stress can cause partial discharges within the insulation, which result in erosion and eventually failure of the cable at that point. It can be seen from Fig 6.114 that there is also a very high stress in the air where the screen terminates, and this may be sufficient to cause discharges in the air at working voltage. It is therefore necessary to incorporate a stress control system into the termination of II kV cables. Stress control can be provided by a number of methods such as the use of high permittivity materials, non-linear materials or resistive coatings applied over the insulation from the screen end for a defined distance. These materials may be obtained in heat shrink or tape forms. Heat shrink components are manufactured from cross-linked materials that have been expanded at high temperature and then cooled in this expanded condition. Since the material is cross-linked, it retains a 'memory' of its original shape and size. When it is subsequently heated during installation (using a blow-lamp or hot-air gun), it tries to recover its original size and hence shrinks down tight onto the cable. A further method of stress control is the use of a stress cone. This works by controlling the capacitance in the area of the screen termination to reduce the stress, as shown in Fig 6.115. Stress cones were originally formed by applying layers of insulating tape to build up the cone shape, then applying layers of semi-conducting tape. This process was very skilled and time consuming, and has now been replaced by the use of moulded rubber terminations. Moulded rubber stress cones are manufactured for use on cables having extruded screens, so an adapter has to be included when they are used on cables having varnish and tape screens. This adapter fits over the varnish
:NSULATCN
CCNCLC cCR
REINFORCING INSULATING PORTION FLUX LINES
and tape screen to present an interface to the stre ss cone similar to that of an extruded screen. A co rn _ plete termination is shown in Fig 6.116. From t h is figure, the cable copper tape screen can be seen t er _ minated on the gland and, above this, the screen adapt er and stress cone. Stress cones of this type are used withi n cable boxes having air clearances which are located indoors in controlled environmental conditions, such as switchrooms, where condensation will not occur. In locations where terminal boxes are liable to con_ densation (such as on motors and transformers) o r where air clearances cannot be achieved, it is necessary to use a fully insulated termination. A fully insulated termination is shown in Fig 6.117 and these are kno wn as elbow terminations because of their shape. Elbow terminations are fully screened by an oute r layer of semi-conducting material which is earthed. An inner semi-conducting screen is provided which is held at phase potential by contact with the conductor fitting. This arrangement prevents high stresses and hence discharges in the air surrounding the conductor fitting. A stress relief adapter is provided to control the stress, in a similar manner to the stress cone, where the cable insulation screen is terminated. Quite clearly these elbow terminations are more expensive to purchase and install than stress cones and should only be used where essential. Moulded rubber terminations have been used extensively in power stations since the introduction of elastomeric cables. Their selection was based on the results of a series of tests carried out by the Central Electricity Research Laboratories. These tests showed that moulded rubber terminations were relatively easy to install and provided excellent stress control as indicated by a lack of partial discharge activity at up to three times working voltage. Moulded rubber terminations also provide a ready means of disconnecting cables for testing. Suitable test criteria for terminations are given in Engineering Recommendation C89, May 1986 — 'Performance specification for terminations on polymeric insulated cables'. It is important to ensure that the partial discharge performance of terminations is matched by that of the cable to enable the completed installation to undergo a partial discharge test. It is recommended that all 11 kV polymeric cables (complete with terminations) be subjected to a partial discharge test as part of the commissioning procedure.
10 Fire barriers
10.1
Fic. 6.115 11 kV cable screen termination with stress control
540
Introduction
A fire barrier is, as the name suggests, a physical barrier which inhibits the progress of a fire and hence li mits its damaging effects. In this context, the tern) 'damaging effects' includes not only the flames and their associated heat of combustion, but also anY
Fire barriers
..;s1
541
1PP Chapt er 6
Cabling
1111.11111111 TES
,
mOLn_DED CONCuC7I'vE SCREEN EAP - ,NG
DEAD END PLUG
S ES
INSuLAT!ON
CONDUCTOR CONNECTOR
I NTE R AJA L
SCREEN CABLE REDUCER
FIG. 6.117 11 kV elbow termination (diagrammatic)
s moke and corrosive and toxic gases generated by that combustion. Fire barriers form an integral part of the CEGB's design philosophy for cable installations since they are used to provide 'segregation' between groups of cables and/or electrical plant. The concept of segregation is described in detail in Section 2.1 of this chapter. A fire barrier may be part of the power station civil structure itself, i.e., concrete or blockwork walls, ceilings or floors, or it may be a purpose designed prefabricated partition. Requirements for segregation are therefore taken into account when the civil structure of the power station is being designed. However, there are many cases where it is impracticable or prohibitively expensive to provide civil structure fire barriers for segregation and, in situations like these, pre-fabricated fire barriers are used; it is these pre-formed partitions, colloquially known as fire barriers, with which this section is chiefly concerned. Pre-fabricated fire barriers (Fig 6.118) are formed from non-combustible fibreboard panels which are mounted onto a framework, usually of C-section steel channels. The panels are generally mounted on either side of the steel framework leaving a gap of typically 100 mm. This 'double-skin' format is required to provide the necessary level of fire withstand performance. In some cases, the air gap between the two panels is filled with mineral fibre to further increase the degree of thermal insulation provided by the barrier which, in turn, reduces the temperatures on the unexposed face during a fire. 542
The panels themselves are proprietary items and may typically be composed of an asbestos-free fibre/ cement reinforced by galvanised steel sheet, mechanically-bonded to the fibre during manufacture by pressing tangs into the fibre surface. This is the type of panel illustrated in Fig 6.118. An alternative panel type is formed from glass fibre reinforced cement. The steel sheet and the glass fibre reinforcement are provided to improve the mechanical properties of the panel. The steel framework onto which the panels are fixed will itself be rigidly fixed to the civil structure at the barrier location. 10.2 Performance requirements The level of fire performance required from fire barriers varies dependent upon the type of power station in which they are installed. In fossil-fired and hydro power stations, segregation is provided primarily to limit economic loss resulting from a 'small' fire. (A small fire is defined as one which can be extinguished within one hour.) Consequently, fire barriers used for this type of segregation must be capable of containing the effects of that fire for a minimum period of one hour. In the case of nuclear power stations, irrespective of the type of reactor employed, additional segregation is required to ensure that the reactor can be safely shutdown in the event of a fire. As explained in Section 2.1.2 of this chapter, the segregation philosophy used for nuclear power stations dictates that two different
Fire barriers
,
C) Ornrn
5rnon GALVANISED STEEL SHEET
STEEL . CHANNEL 3AR
FIBRE CEMENT
Flo. 6.118 Pre-fabricated fire barrier of segregation, or segregation classes, are defined. ['I ce are, therefore, two different levels of fire barrier ; , ,Jformance needed to provide these two classes of Fire barriers for segregation Class I need to be able ,ontain the effects of a 'major' fire, defined as one can be extinguished within four hours. They also be required to withstand the effects of other . .:/ards which may occur locally to that barrier, such ini Aks from a turbine disintegration or a hot gas (the latter being specific to gas-cooled reactor Because of these more onerous requirements, •::-e barriers for segregation Class I are generally part he civil structure. egregation Class II fire barriers must he capable containing the effects of a 'small' fire (as defined The same designs of barrier are therefore o provide Class II segregation as are used for 0, 11-tired and hydro stations. \I the time of writing, pre-formed fire barriers have : I fo rmally been demonstrated as being capable of .niding Class I segregation. However, development
work aimed at the formal approval of partition fire barriers (and their associated fixings and penetration seals) is in progress, which will provide this performance. In addition to this, the UK design for PWR power stations also calls for a 3-hour rated fire barrier. Development work in this area is also in progress. It is important to note that the basic performance requirements and hence test methods for such barriers, will be of the same form as those set out for Class II fire barriers except that they must be maintained for the appropriate longer period. Class II fire barriers are further divided into two categories dependent upon the function which they fulfil. Category 1 fire barriers are used to provide the required segregation defined above. Category 2 fire barriers are employed within a given segregation 'zone', acting as smoke and fire stops, thus restricting the extent of fire damage and also assisting fire detection and fire fighting. This categorisation is merely one of functional definition as the performance requirements for both Category I and Category 2 fire barriers are the same. 543
Chapt er 6
Cabling
fire barrier. The second configuration shows an ex _ ample of a Category 2 fire harrier used to provid e zoning within a particular segregation area. Here, the most important features are the so-called 'penetration s , . Since Category 2 barriers provide fire protection withi n a segregation area they will, by definition, have cable
This distinction can be seen more clearly by examining typical cable installation fire barrier configurations, examples of which are shown in Fig 6.119. Configuration 1 shows a simple plain wall, partition type fire barrier. This type of arrangement is most li kely to be used to provide a Class II, Category 1
o
CARIES SUPPORTED ON STEELWORK
FIRE BARRIER
CONFIGURATION I TYPICAL CATEGORY 1 PLAIN WALL TYPE FIRE BARRIER
BARRIER FIXING FRAMEWORK
PIPEWORK PENETRATION PRE PROTECTION PIPEWORK)
BARRIER , x NG ;RAJA EWORK
I
•
FIRE BARRIER
' CONFIGURATION TYPICAL CATEGORY 2 CROSS-BARRIER INCORPORATING CABLE AND PIPE PENETRATIONS AND FIRE DOOR
• : CABLE PENETRATIONS i SINGLE AND MULTI OPENING' MAY OR MAY NOT INCLUDE CABLE suppoRT STEEL
r-11 • • • GLAZED PIPE DOOR
ELEVATION
SECTION X X
iNCLUDING OPERATING .41EChIANISMS AND SEALS
CANTILEVER ARMS
CABLE RISER WALLS
FIRE BARRIER INCORPORATING SUPPORT ARRANGEMENT
PENETRATIONS
EL E VA TIO N
Fic. 6.119 Typical fire barrier configurations
544
CONFIGURATION 3 TYPICAL CATEGORY 2 HORIZONTAL CROSS BARRIER IN A CABLE RISER
Fire barriers and other services (e.g., pipework and personnel access Joors) passing through them. It is obviously necessary IC) ensure that these penetrations do not jeopardise inle.rity and tire performance of the barrier as a , hc This point is addressed in more detail below. ,imilar way, Category 2 fire barriers may also in .1 fl.talled in a horizontal alignment to sectionalise fl mes (or risers). Such a barrier is shown in the u
:bird configuration. The effectiveness of a fire barrier in containing a fire mil be chiefly determined by two factors:
• :■ 13,2nitude and type of fire. •
proximity of the fire to the barrier.
1 - 1 1 ce are explained in more detail in the following bsections. Magnitude and type of fire 10.2.1 \kill depend on the type and quantity of combusHMe material which is fuelling the fire. When probarriers for cable installations, the main dine .ource of combustible material is, of course, the cables ,,elves in the form of their insulation, bedding and i hm ,heathin2 materials, all of which are combustible. The performance of cables under fire conditions throughout the 1970s and early-to-mid 1980s, been jiiefly governed by the use of PVC as the major cable a p,ulation, bedding and sheathing material. Whilst PVC po,sesse.s excellent electrical and mechanical properties, a also has a number of undesirable fire performance Characteristics which must be allowed for when selecting tire barriers. Fire performance properties are discussed in detail in Section 8 of this chapter, but the most important a‘pecis which must be considered are summarised as .0[1ows: • The ability of these materials to propagate a fire, both vertically and horizontally. • \\. hen PVC and to some extent the other commonused materials burn, they generate considerable quantities of dense smoke and toxic, acidic fumes and gases which may rapidly reduce visibility and render the atmosphere hostile to humans in confined spaces. This is aggravated by the presence of the Category 2 fire barriers. The main constituent of these combustion products is hydrogen chloride ‘‘hich readily combines with available moisture to Form hydrochloric acid. (Water is produced during combustion as well as being present in the atmosphere.) Even after a fire has been extinguished, the corrosive deposits which result may cause long term damage to sensitive equipment such as relay contacts. • The gases driven off by the combustion of PVC are also highly flammable. Indeed, it is believed that It is the burning of these gases, with recorded flame
temperatures in excess of 1000 ° C, which contributes most to the propagation mechanism. During the next few years, completely new cable insulation, bedding and sheathing materials will begin to supersede PVC. These new materials have been specifically developed with their fire performance in mind and have the advantage that when they burn, they give off significantly reduced quantities of smoke and toxic, acidic gases, whilst still maintaining low fire propagation characteristics. It is unlikely, however, that the total heat of combustion generated by cables using these new materials will be significantly lower. The performance requirements for cable installation fire barriers are therefore unlikely to change significantly as a result of these developments in cable technology. Despite the fact that cable components are the major source of combustible material in a cable installation, it must be pointed out that fires started by internal faults in the cables themselves are very rare. Indeed, with correct design of the cable installation, especially particular care in power cable sizing and protection, cable faults can be virtually eliminated. However, cables, by the very nature of their service function, easily become involved in fires caused and fuelled by other sources. Cable tunnels and flats are areas of an operating power station in which rubbish may accumulate, even with the most rigorously applied 'good housekeeping' policies. Their physical location can mean that liquid spillages may also find their way into them. Such spillages could include flammable lubricating and cooling oils. These are important additional factors which must be allowed for in the design of cable installation fire barriers. Sources of ignition and fuel will of course be the same, irrespective of whether PVC or the new range of materials is used in the cable construction.
10.2.2 Proximity of the fire to the barrier Having identified the nature of the fuel source and its combustion characteristics, it is necessary to consider how near a potential hazard may be to the protective barriers. An ideal cable installation layout would ensure that the fire barriers were installed some distance away from the major source of combustible material, hence reducing the level of performance required from the barriers and consequently their cost. This invariably proves impractical, for two reasons. Firstly, the space available for cable routes is limited by civil structure costs and, secondly, as has already been mentioned, that cables need to pass through Category 2 barriers (i.e, those used to provide zoning within a given segregation area). This type of fire barrier will, therefore, have the principal source of combustible material in intimate contact with the barrier. These two factors dictate that all Class II fire barriers must be designed to provide the required level 545
Cabling of performance assuming the fire to be immediately adjacent to the barrier. In this way, the most onerous practical conditions are catered for at the design stage. It is clear from the above, that the nature of the fire hazard present in power station cable installations is unique. The CEGB has therefore produced its own internal technical specification which sets out performance requirements, This specification is becoming increasingly well known throughout the fire barrier manufacturing industry. These technical requirements are discussed in more detail in the following section.
Chapter 6
1
000
900
800
7
10.3 Fire test requirements It is considered that the only representative method of assessing the performance of a fire barrier is to conduct a full scale fire test, i.e., to place a sample of the fire barrier in front of a 'test fire' and examine how it performs. To make this test fully representative of 'as-installed' conditions, the specimen barrier must include all fixings, accessories, penetrations, doors, etc., which would be included in use. This is the philosophy set out in British Standard Specification BS476: Part 8: [24], the document which forms the basis of the CEGB's fire test requirements. This specification primarily addresses test methods and performance criteria for materials used in building construction. Whilst this standard was conceived for more conventional applications, such as factories and other public buildings, its philosophies are obviously equally applicable to the power station cable installation. In order to make a fire test 'repeatable and hence provide a means of comparing the performance of one barrier construction with another, it is necessary to define a standard set of fire conditions. The severity of this test fire is specified in terms of a time/temperature curve. BS476: Part 8: 1972 specifies such a time/ temperature relationship, to which the test furnace should be closely controlled within laid down limits for the duration of the test. This is the so-called `BS476 fire test curve' and it has been derived from the burning characteristics of typical materials found in normal building environments (such as wood, fabrics, etc.). General construction fire barriers such as blockwork walls have been designed and tested to these requirements. This fire test curve is shown in Fig 6.120. Other time/temperature test curves exist for special applications however. A typical example is the hydrocarbon fire curve developed by the Mobil Oil Company which is used extensively throughout the petrochemical industry. This fire test curve recognises that when hydrocarbons burn, they do so initially at much higher temperatures than do the materials considered by the British Standard. The Mobil curve therefore features a higher initial rate of temperature rise than does the British Standard curve. In the longer term, if there is sufficient fuel available, a building material fire will 546
00
I., 600
2 500
400
300
200
1 00
0
10
20 30 40 TIME q+110 TEST MINUTES(
50
60
FIG. 6.120 Fire test curves (BS476 and Appendix A)
attain higher temperatures than the hydrocarbon fire. Again, this is reflected in the profile of the two ti me/temperature curves. Similarly, cable insulation, bedding and sheathing materials have different burning characteristics from conventional fire hazard materials as a result of the combustion of the gases driven off. The CEGB fire barrier specification therefore contains a fire test curve, known as the 'Appendix A' curve, which acknowledges this fact. This test profile has the high initial rate of temperature rise of the hydrocarbon curve, flattening out at a temperature of 1050 ° C and is also shown in Fig 6.120 for comparison with the British Standard curve. Since Class II fire barriers must be capable of containing the effects of a cable installation fire for a minimum of one hour, a one hour long fire test is conducted on representative barrier specimens. BS476: Part 8: 1972 identifies three major properties of the barrier which are indicative of its level of protection and these are: • Stability
The ability of the fire barrier to remain intact and in a stable condition without excessive deformation for the complete duration of the test.
Fire barriers This property is assessed by examination of the harrier both during and immediately following the st. It is essentially a measure of the strength of the (e harrier assembly under the extreme temperatures of the fire.
•
T weg
oly
In addition to remaining 'stable', no cracks
penings must develop in the barrier during or other o the test which could affect its ability to prevent
of fire from one side of the barrier to ,he other. in cable installations, this aspect is particularly important since such openings could permit and fumes from one side of the pa ssage of the gases barrier to the other. A test is passed, therefore, only if [here is virtually no leakage of hot gases or smoke through the barrier; particular attention being paid [GI joints, penetration seals and doors. It is difficult, however, to quantify exactly what constitutes 'acceptable' leakage in this context as it will depend very much on the size and complexity of the barrier assembly being tested. The British Standard calls for integrity to be measured by holding cotton wool pads immediately over any cracks or fissures, a test pass being recorded if the pads do not catch fire. This is not considered to achieve adequate demonNtration that smoke and fumes will not pass through the openings; the performance of the barrier is therefore checked by a careful visual examination throughout the test. t h e spread
• Insulation The insulation performance of a fire barrier is determined by measurement of temperatures on the unexposed face during the fire test. \\ hen assessing the thermal resistance of the barrier, ii
it
important to consider the nature of the cable
materials local to the barrier. Because PVC can start to cmil combustible gases from upwards of 200 ° C, it is important to limit the temperatures on the unexposed Lice by barrier design. Temperatures at various points
on the unexposed barrier face are therefore monitored throughout the test using thermocouples. A test pass recorded if the mean temperature of the-unexposed race rises by no more than 140 ° C and if the temperature at any critical hot spots (for example, bolt heads) rises hy no more than 180 ° C. These temperatures allow for ;lie fact that the cables will not actually be in contact Lt h the barrier surface but will be protected to some degree by their penetration seals. As illustrated by Fig 6.119, many different fire Harrier configurations will be used in protecting a cable
InNtallation. It may therefore be necessary to conduct
separate fire tests on a number of different barrier
,
.ontigurations in order to have complete confidence
t. n the barrier installation as a whole. Since this would Ce l
"Pensive, care is taken to ensure that a full scale
est assembly covers as many of the practical barrier
Ar
rangements as possible. For example, a successful on an arrangement such as configuration 2 in 1ig 6.119 would normally be considered as demon-
strating the performance of the plain barrier arrangement of configuration 1. The case is not so clear cut when configuration 3 is examined and a separate test on such an arrangement would most likely have to be carried out. From the above, it is clear that care must be taken in assessing whether fire test performance data may be applied to a particular practical configuration. As a closing note on full scale fire testing, it is important to remember that a fire barrier which has successfully maintained stability, integrity and insulation during a fire test has performed in that manner under test fire conditions only. Fire barriers passing such tests are often referred to as having a 1 hour (say) rating. It should be appreciated, however, that the I-hour rating relates to the specific characteristics of the test. Since all real fires have differing and unique characteristics, the fire test cannot ever be an absolute guarantee of performance. On the positive side, it must be remembered that the test fire is immediately adjacent to the fire barrier whereas in practice this is unlikely to be the case. It should also be noted that test fire conditions make no allowance for the fastacting fire fighting systems which the CEGB usually employs to protect its cable installations for economic reasons. As well as the main full-scale fire performance tests described above, the CEGB's specification also calls for non-combustibility and surface spread-of-flame tests to be carried out on fire barrier materials. The non-combustibility test is carried out in accordance with BS476: Part 4 [251, which calls for specimens of a predetermined size to be heated in a small, closely temperature controlled, electrically-heated oven. During the test period, the current in the heating coils is held at a fixed value which, after a period of stabilisation, produces an approximately constant oven temperature. The test specimen is then introduced into the oven and held there for 20 minutes during which time the oven temperature is closely monitored. Any increase in the oven temperature (above a certain tolerance value) is then deemed to be attributable to the combustion of the test specimen. A sample giving such a temperature rise would therefore fail the test. In addition to this temperature measurement, any sustained flaming of the specimen is also noted. If flaming occurs continuously for more than 10 seconds, this is also deemed to be a test failure. It is clear therefore, that the term 'non-combustible' as determined by this test procedure, is not absolute. The British Standard defines non-combustible materials as those which 'make little or no thermal contribution to the heat of the furnace and do not produce a flame', which is consistent with CEGB philosophy for fire barrier material combustibility. The surface spread of flame test is carried out in accordance with BS476: Part 7 [26]. This test provides a method for measuring the lateral spread of flame along the surface of the fire barrier -
547
C hapt er 6
Cabling panels when vertically orientated, and a classification system based on the rate and extent of flame spread. The test method has been designed to take account of the combined effect of factors such as ignition characteristics and the extent to which the surface of the test specimen spreads the flame. The influence on these factors of any underlying materials, in relation to their ability to influence the rate of fire growth, is also taken into account. In this method, specimens of the fire barrier panels are subjected to a specified radiative heating regime v.ith a small gas ignition flame at one end. The horizontal spread of flame from this ignition source is measured at 1.5 minutes and 10 minutes into the test, and the progress of the flame-front determines the surface spread-of-flame classification given to the material. The most onerous classification, which is that required by the CEGB for its fire barrier panels, is Class I. To meet Class I requirements, the flame front must not progress beyond 165 mm from the ignition source after the 10-minute test period.
10.4 Additional performance criteria In addition to the basic fire test performance criteria, the CEGB also dictates that its fire barriers provide the following features: • Design performance over a lifetime of 40 years in a power station environment without the need for maintenance. • Suitability for use in damp and wet conditions. • Freedom from asbestos in their construction.
• Freedom from materials which emit any corrosive or toxic fumes or smoke on the unexposed face of the barrier under fire conditions. • Defined minimum mechanical strength. • Capability of withstanding the pressure rise associated with fires in sealed cable tunnels. • Capability of withstanding in-service levels of vibration without reduction in fire performance. • Barriers must not fail in such a way as to damage other plant (including cables) during a seismic disturbance of a specified magnitude (requirement for nuclear power stations only). A wide range of tests are carried out on barrier samples which are designed to demonstrate the above qualities. These tests include: • A hose stream test to verify that the thermal and mechanical shock of a hose stream being suddenly played on a hot fire barrier does not cause catastrophic failure. • The following mechanical strength tests: 548
(a) I mpact withstand. (b) Modulus of elasticity and bending strength. (c) Mechanical strength after wet cycling. (d) Pressure rise due to combustion (simulated statically or by analysis). • Water absorption. • Seismic qualification, usually by analysis based upo n dynamic tests on representative fire barrier sampl es. It is more difficult to demonstrate that the materials used will not age significantly over their 40-year de s i gn
life. The type of testing which is carried out very much depends upon the materials used, but a common feature is the application of heat, either a continually - applied elevated temperature or some form of thermal cycling. In some cases, the materials used to construct the fire barrier are standard building materials for which ageing data is already well established. In these cases further testing is not necessary. 10.5 Fire doors It is not possible to specify requirements for fire barriers without giving careful consideration to the design of fire doors.
Fire doors may effectively be considered as personnel penetrations, and they bring with them their own problems in ensuring adequate fire performance. Obviously, the presence of the door must not detract from the fire performance of the barrier in which it is located. This means that special care must be taken at the jamb assembly to ensure that integrity and insulation requirements are met. It may be particularly difficult to achieve the required fire performance whilst still providing doors which provide satisfactory emergency egress for personnel. Another problem which arises with doors is that for ventilation purposes they often need to be latched open during normal operation. This means that a fastacting fire detection system must be provided to trigger door release in the event of a fire. The closing mechanism must obviously ensure that the required seal is made on closing. 10.6 Penetrations Penetration seals are required in order to seal around openings where cables (and other services such as pipework) pass through fire barriers. It is a fundamental requirement, therefore, that the presence of these penetration seals does not degrade the fire performance of the barrier in which they are located. Configurations 2 and 3 in Fig 6.119 show typical examples of the application of these seals, here shown specifically installed in pre-formed type fire barriers. They could, however, equally be installed in walls,
Fire barriers floors roof soffits, etc., since all of these may be , ° nsidered as fire barriers. • There are three basic types of penetration seal; rigid, ' bie and pre-formed, each of which is described ,i ic
1H-icfly as follows: These are usually modified plasters • Ri,id seals inert materials such as vermiculite or of made up Inked at site to form a paste. pcar lite , which are rw i,ater based, they are placed around the peneB c1 trants by trowelling and then form a rigid seal by caporation at room temperature. When set, they effectively form an extension of the fire barrier in hich they are located, containing the fire in much the same way as the barrier itself. They have the additional advantage of acting as a heat sink which retards the conduction of heat along the conductors of the cable during a fire. This type of seal, whilst being inexpensive, suffers from two main problems. Firstly, it requires the time,J)nsurning, labour intensive process of damming at penetration prior to forming. This is usually e ach carried out using plywood or a similar material. Secondly, once a seal has been formed, it is then difficult to add further cables. It is undesirable to leave the sealing of penetrations to the very end of cable installation as the construction period itself is the time of greatest fire hazard due to high personnel presence. Despite these two disadvantages, these are the traditional type of seals which have been used in a wide variety of industrial applications for many years. There is, however, a new form of rigid penetration seal which is now generally available in the form or a two-part silicone elastomer which, when mixed, ■ ;ill cross-link at room temperature to become rigid. This mixing takes place at the head of special pumping equipment which is used to install this type of ',cal. Because the seal material is a liquid when first applied, it is able to mould itself to the contours or the penetrations. During a fire, the seal material burns to form a surface layer of char. It is this char layer which prevents further combustion of the seal and hence restricts the fire. Again, prior to forming the seal, damming materials need to be installed at each penetration. In this case, the damming is formed from ceramic fibre hoard which is not removed after curing and forms part of the finished penetration seal assembly. This type of seal suffers from the same disadvantages as the modified plasters described above and is also more expensive. Furthermore, it is also necessary to use specialised installation equipment and requires trained applications staff in order to ensure a consistent standard of seal. It is, however, much faster to install than the plaster type seals and it also has a pressure withstand capacity, which the plaster type seals do not have. This can be an advantage where
it is identified that a pressure rise due to combustion in a sealed area may exist.
• Flexible seals A variation of the silicone elastorner rigid seal described above is formed by the addition of a foaming agent to one of the components in the mix. Once mixed, the two components begin to cross-link at room temperature but, whilst doing so, hydrogen gas is generated which causes foaming to occur. This foaming leads to expansion of the seal material which in turn provides a good mould to the contours of the penetrants. Again, ceramic fibre board damming is required at each penetration prior to sealing and this forms part of the completed penetration seal assembly. The main advantage with this type of seal is the relative ease with which additional cables may be added at a later date. The fully cross-linked foam may easily be cut with a craft type knife, as can the ceramic fibre board by means of a special tool. If the hole in the foam is cut slightly undersize to the penetrant, its natural springiness will ensure a good smoke-seal without the need to re-apply sealant. As with the rigid elastomer seal, expense may restrict the use of these seals which require trained staff and special equipment to install. • Pre formed These types of seal, sometimes known as 'cable transits', are in the form of 2-part, semiflexible, pre-formed blocks which are placed around individual cables. These blocks, along with 'blanks' where necessary, are slid into a special frame formed around the inside of the penetration. Clamping screws are used to achieve a tight seal around the penetrant. During a fire, the block material is consumed very slowly, hence the thickness determines the level of fire performance. The design intent of these cable transits was the easy addition and removal of cables after formation. However, it is necessary to keep a complete range of block and blank sizes to cover for all cable sizes and penetration configurations. Use of these transits means that cable support ladders must be stopped on either side of the fire barrier, hence giving rise to the need for additional cable steelwork supports. Also, the fact that blocks are placed around individual cables makes this a very time-consuming and expensive sealing method and consequently they are rarely used by the CEGB. -
As mentioned, it is essential that penetration seals provide the same level of fire performance as the barriers in which they are located. It is therefore necessary to incorporate examples of typical sealing arrangements in the full scale fire test assembly. Particular attention is paid to the unexposed face temperatures around the seals which are a potential weak point in the barrier assembly. • 549
Cabling As with fire barriers, in addition to the basic fire test performance criteria, the CEGB also dictates that its penetration seals provide the following features: • Design performance over a lifetime of 40 years in a power station environment, • Suitability for use in damp and wet conditions. • Freedom from asbestos in their construction. • Capability of withstanding the pressure rise associated with combustion in sealed cable tunnels. • Compatibility with cable sheathing materials. • Capability of withstanding in-service vibration and cable movement due to short-circuit and thermal cycling without reduction in fire performance. • They must not damage cables during a seismic disturbance of specified magnitude (requirement for nuclear power stations only). A further design criterion which must be considered when selecting penetration seal materials, is the effect which the seals may have on the current carrying capacity of power cables which pass through them. Here, two conflicting interests exist. In order to achieve good insulation properties to restrict unexposed face temperatures during a fire, it is desirable for the seal to
be a good thermal insulant. This does, however, restrict the conduction away of heat generated in the power cables due to copper losses under normal operating conditions. Thus it may become necessary to derate the power cable to accommodate the seals. This in turn may lead to the use of larger cables sizes to supply particular loads. The rigid plaster type seals will be less of a problem in this respect than the other seal types, since they are more thermally conductive. 11 Earthing systems
11.1
Introduction
The purpose of an earthing system is to provide an
adequate path for earth fault currents to return to the system neutral. This has to be performed in a manner which ensures 'safety to personnel', i.e., without giving rise to dangerous touch, step or transferred potentials. In addition, to prevent damage to plant, the rise of earth potential under fault conditions must not result in breakdown of insulation. In all cases, the system design must be such that enough fault current will flow to operate the protection devices and disconnect the fault. To meet these needs, an earth system must include earth electrodes to allow current to flow into the ground to remote system neutrals, and also a network of conductors to allow fault current to flow between plant within the station site. In this context, in accordance with British Standard Code of Practice 550
Chapter 6 1013: 1965, Clause 215, it is a requirement that if two or more stations are adjacent on what may b e considered to be one site, then the earthing systems a re to be interconnected to form a single earthing system. This applies to a number of generating stations on one site, and also to power stations and transmis s i on substations on a common site. When reading this section it should be borne i n mind that earthing is closely associated with light n i ng protection, power cable ratings and gland bonding, and therefore reference will also need to be made to th e sections covering these topics.
11.2 Differences in earth potential 11.2.1 Definitions When earth fault currents flow to ground, a potential gradient is formed around the earth electrode due to the resistance of the ground. This potential gradient is greatest adjacent to the earth electrode and reduces to zero or true earth at some distance from the earth electrode. Three methods of contact with these pot. tials are considered and defined as step, touch and transferred potentials. These are shown diagramma.. tically in Fig 6.121 which is discussed as follows: • Step potentials Person 'a' on Fig 6.121 illustrates 'step potential'. Here the potential difference V 1 seen by the body is limited to the value between two points on the ground separated by the distance of one pace. Since the potential gradient in the ground is greatest immediately adjacent to the electrode area, it follows that the maximum step potential under earth fault conditions will be experienced by a person who has one foot on the area of maximum rise and the other foot one step towards true earth. • Touch potential Person 'b' on Fig 6.121 illustrates 'touch potential'. Here the potential difference 112 seen by the body is the result of hand-to-both-feet contact. Again the highest potential will occur if there were a metal structure on the edge of the high potential area, and the person stood one pace away and touched this metal. The risk from this type of contact is higher than for step potential because the voltage is applied across the body and could affect the heart muscles. • Transferred potential The distance between the high potential area at the electrode and that of true earth may be sufficient to form a physical separation rendering a person in the high potential area immune from the possibility of simultaneous contact with zero potential. However, a metal object having sufficient length, such as a fence, cable sheath or cable core may be located in a manner that would bridge this physical separation. By such means, zero earth potential may be transferred into a high po1 tentiaI area or vice-versa. Person 'c' in Fig 6.12
Earthing systems
STA" ON
PO , NT
PILOT CABLE HAVING coNrrNuous METALLIC SHEATH INSULATED THROUGHOUT BUT WITH BOTH ENDS EAposE0 SHEATH BONDED TO MAIN EARTH GRID AT SUBSTATION END ONLY
I ALE TAR TN
EOU.POTENTIAL LINES DURING FLOW OF EARTH FAULT CURRENT
BURIED ELECTRODE
FIGURE
CURRENT FLOW PATH
POTENTIAL DIFFERENCE
TYPE
STEP PO T ENTIAL
'eg leg
TOUCH POTENTIAL
arm•bady•iegs dun tt0Cly-arrn
vi
arrn•ocKly leg
T
i
• TRANSFERRED POTENTIAL TRANSFERRED POTENTIAL
Fin. 6.121 Differences in earth potential
illuqrates the case of a high potential being transferred into a zero potential area via the armour of a cable. Since the armour is bonded to the main earth Ind at the power station, the voltage V3 will be he full 'rise of earth potential of the power station'. :
In the illustrated case, the person is making simultaneous contact hand-to-hand with the cable sheath and true earth. However, if the person is standing an [rue earth then the voltage V3 seen by the body ,: ould be the result of a hand-to-both-feet contact. Person 'd' in Fig 6.121 represents the case of zero [' o[ential being transferred to a high potential area \ id a cable core which is earthed at the remote point. In this case, the voltage V4 is lower than V3 o hich represents the station rise of earth potential, because person 'd' is located some distance from the main earth electrode and therefore is subject to the ground potential gradient. Quite clearly if person 'cl' ii ad been on or touching the main electrode he would hl asre experienced the full rise of earth potential V3. Franslerred potentials are therefore considered to ..airy the greatest risk since the shock voltage may he . equal to the full rise of earth potential and not a iraction of it, as is the case with step or touch [
pa entials.
11 2.2 Acceptance criteria cceptance criteria are related to the rise of earth ;otential and its duration in the following manner:
(a) For high reliability systems, i.e., systems having high speed protection, the maximum permissible rise of earth potential without special precautions is 650 V. This requirement, given in Engineering Recommendation S5/I, is based on limits set by the International Telegraph and Telephone Consultative Committee for installing telephone equipment without special protection for personnel or equipment. A duration is not given for the clearance time associated with high reliability systems, but this is generally accepted as 0.2 seconds. Although this value of 650 V originates from requirements for telephone equipment, it is now also used as a criterion for safety generally. Therefore, providing this limit is not exceeded, experience has shown that no special measures are necessary in respect of potential rise, step, touch or transferred potentials. (b) For systems protected by overcurrent protection, the maximum permissible rise of earth potential without special precautions is 430 V. This requirement, also taken from Engineering Recommendation S5/1, is again based on CCITT recommendations for telephone equipment. Once again, no fault duration is given for this condition but using the criterion given in (a) and extrapolating on an 1 2 t basis, for the 430 V limit a maximum duration of 0.46 seconds is obtained. As for (a), providing the criterion is not exceeded, no special 561
Cabling measures are required in respect of step, touch or transferred potentials. (c) British Standard code of practice CPI013: 1965 (Clause 213) requires that the potential difference between two normally earthed items to which personnel may have simultaneous contact should not exceed 55 V. Bearing in mind the criterion given in (b), this limit of 55 V is applied to all rises of earth potential that exist for durations in excess of 0.46 seconds. (c1) If the criterion given in (a), (b) and (c) cannot be
complied with, then special precautions must be taken to protect personnel and plant. An example of precautions to protect against transferred potentials is the use of isolation transformers on incoming telephone lines. A further example is the provision of local bonding to give immunity by ensuring that all metalwork to which simultaneous contact can be made is at the same potential. Guard rings buried at increasing depths around an electrode can be used to modify the ground surface potential to protect against step potentials.
11.3 Earthing systems design When considering the design of earthing systems it is useful to bear in mind that earth fault currents have to return to their own system neutrals. This means that whilst a common earth system for all equipment is employed, it can be analysed in two parts depending on whether the neutral of the system feeding the fault is within the power station or is remote. The following Section 11.3.1 deals with 400 kV, 275 kV and 132 kV systems where a significant proportion of the earth fault current will flow via the earth electrode to a remote supply source. Section 11.3.2 deals with system voltages up to and including generator voltage, where the system neutral is within the power station and therefore the vast majority of earth fault current will flow in the metallic bonding system. 11.3.1 Systems having remote neutrals
400 kV, 275 kV and 132 kV systems have neutrals that are outside the confines of the power station and therefore the earth fault current flows back to the source via the ground and any EHV cable sheaths or aerial earth conductors. The proportion of fault current returning down each path will be dependent on the path impedance. Under such fault conditions the whole power station earth network will be raised in potential with respect to remote earth. The rise of earth potential will be the product of the current returning through the ground and resistance of the station earth. Since these EHV systems are classed as high reliability, the maximum allowable rise of earth potential under fault conditions without additional precautions is 650 V as discussed in Section 11.2.2 (a) of this chapter. 552
Chapter 6 Since the earth fault current that flows into the ground is associated with the EHV systems, the mai n earth electrodes should be adjacent to plant connected to the EHV system (e.g., generator and station transformers). This is to enable earth currents to flo w to ground close to the fault location, thus restricting th e fault current flowing through the station earth system interconnections and minimising the potential gradients across the station. In addition to these main ea rt h electrodes, it is normal practice to install a number of secondary electrodes to reduce the overall station resistance and limit potential gradients across the site A typical station earth system arrangement is show n in Fig 6.122. The earth electrode system is designed by calculating in sequence the following parameters: • Maximum earth fault current that has to return to remote sources. • Minimum size of electrode required to transfer fault current into the ground. • Resistance of these minimum size individual electrodes. • Consequent overall station earth resistance. • Proportion of current that returns to source via the ground. • Resultant rise of earth potential. • If the rise of earth potential is unacceptable, the size of individual earth electrodes is increased and the calculations repeated. • If the rise of earth potential cannot economically be reduced to an acceptable level, other measures to protect personnel and plant must be considered. This process is explained in greater detail in the remainder of this section and a worked example is given in Section 11.4 of this chapter. For earth electrode sizing it is only that proportion of EHV system earth fault current that has to return to remote neutrals that is of interest. Therefore, due account should be taken of on site' contributions to fault currents. For example, where generator transformers are connected to the 400 kV system, any contribution to the 400 kV earth fault level from on site' generation can be ignored when sizing the earth electrodes since the current will flow through metallic connections and not into the ground. Before electrode sizing can be started, the soil resistivity at each proposed location must be established using the Wenner four-electrode test described in Section 11.6.1 of this chapter. The first step in sizing an electrode is to calculate the minimum surface area that is required to dissipate the current into the ground without undue heating and drying out of the soil local to the electrode. For these calculations it is considered prudent to ignore all EHV cable sheaths and overhead
Earthing systems
To - A STATION 1 , EARTH PITT
TO A STATION EARTH PIT
ESOB , NE; TURBINE
HALL
■
5508 NWr
ESSEI.NM ••■•
r
:17:1=r 3
13
-
REACTOR 7
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1:
REACTOR
REACTOR
SERVICES
BU I LDING
ROAD
n 5 7 47.0N . a.INFORMER
STATION TRANSFORMER
ESSO tSE)
ESSE1(SW)
AETP
„,
E508 (SE)
,
11
Fic. 6.122 Typical station earth system 553
Cabling
Chapter 6
line earth conductors, and to assume that all earth fault current returns to the remote neutrals via the electrode adjacent to the faulted plant. Whilst this may appear conservative, in reality the electrode size is normally dictated by its resistance (since this governs the rise of earth potential) and not by its current carrying capability. At this stage the cross-sectional area of the electrode itself should be checked to ensure that it is capable of carrying the anticipated fault current. Such calculations should take into account the estimated loss of metal due to corrosion during the station life. Having established the minimum size of electrode required to carry the fault current, the next step is to calculate the resistance of the station earth system and assess whether the rise of earth potential is acceptable. The first step in this process is to calculate the resistance of each individual electrode as shown in Section 11.4 of this chapter. The overall station resistance is then calculated for all electrodes in parallel ignoring the impedance of interconnecting cables. This greatly si mplifies the calculations and experience has shown that this also compensates for ignoring fortuitous earth paths such as pipes and base slab concrete which cannot be readily identified or calculated. This rise of earth potential will be the product of the station earth electrode resistance and the current flowing through it. As already stated, the earth fault
current will return to remote neutrals via the ground and any overhead line aerial earths or cable sheaths that may exist. The current division will be dependent on the relative impedances of each route. Since the electrode design is dictated by the allowable rise of earth potential, it would be grossly uneconomic to base these calculations on the assumption that all current flows in the ground. Therefore, the division of current between the various paths must be assessed. The amplitude of the earth current returning to neutrals via overhead line earth wires and towers can be 30 70% depending on the number of lines and their length [27]. Therefore, quite clearly, the value of current flowing into the ground will be dependent on the physical location of EHV substations relative to the power station. Where the power station and EHV substation share a common site, at least one metallic connection per generating unit will be provided between the two earthing systems. Earth fault currents can therefore flow via these connections to the earth wires and towers associated with the EHV substation. The magnitude of these currents will depend on the number of overhead lines or cables entering the substation and their lengths. Since power station earth electrodes normally consist of steel piles they have, of necessity, to be designed and installed at an early stage of power station construction. This frequently means that accurate predictions of current division cannot be made at the design stage. It is therefore normal practice to calculate the rise of earth potential assuming the worst case of 70% -
554
of the fault current returning through the ground. The combined resistance of the power station and EHV substation earth systems is used for this calculation. Another arrangement that may be encountered is a power station located a few miles from its associated EHV substation. En such cases it can be assumed that for an earth fault at the power station only 10Wo of th e current would flow in the ground. The rise of earth potential would therefore be the product of this pro.. portion of current and the power station earth syste m resistance. If the calculated rise of earth potential exceeds th e 650 V limit, the size of the electrodes should be increased and their resistances and the potential rises recalculated. In some cases it may not be economically or technically possible to provide an electrode system that will li mit earth potential to 650 V. En such cases the potential rise should be reduced to an economic minimum and additional precautions taken to safeguard against transferred, step and touch potentials. Such measures against transferred potentials would include isolation transformers on incoming telephone and pilot cables, and possibly isolated sections in pipelines or railway tracks entering the site. In addition, step and touch potentials would have to be assessed using the type of techniques given in IEEE Standard 80 [28]. If step or touch potentials are found to be excessive then additional provisions such as guard rings will be necessary. Guard rings consist of a number of ground conductors, connected to the main electrode, and buried at increasing depths around it so that the ground surface potential is modified. A typical arrangement is shown in Fig 6.123. 11.3.2 Faults on internal systems
For system voltages up to and including generator voltage, the system neutrals are earthed within the boundary of the power station and therefore the vast majority of the earth fault current will flow via metallic bonds and not into the ground itself. Equipment operating at generator voltage is considered a special case since it is all bonded to a special earth bar run with the main connections. Consequently, any earth fault current will preferentially flow in this special earth bar rather than in the station earth network. Details of generator main connections are given in Chapter 4. Earth fault currents associated with 11 kV, 3.3 kV and 415 V systems will however return to their neutrals via the station earth network. The station earth network is a mesh of metallic bonds interconnecting the earth electrodes and forming a ring around plant areas. We must now consider the magnitude of earth fault currents associated with these systems. If the zero phase sequence impedance of the system were the same as the positive phase sequence impedence, then the earth fault current would have the same magnitude as that for a three-phase symmetrical fault. In practice for
Earthing systems
Ve POTENTiAu AT GROUND SURFACE WITH RESPECT TO REMOTE EARTH
V,
STEP EOTENUAL WITHOUT GUARD R , NG
........
. . •
EARTH ELECTRODE GUARD RINGS RONDE0 TO EARTH ELECTRODE WITHOUT GUARD RING
WITH GUARD PING
GUARD RINGS BURIED AT INCREASING DEPTHS TO CONTROL GROUND POTENTIAL GRADIENT
FIG. 6.123
Typical guard ring arrangement
Thipsformers it is not possible to obtain identical -dues for positive and negative phase sequence im..1:11ices. Transformers are therefore specified to have ,mo phase sequence reactance as close as possible 10.0' of the positive phase sequence reactance, with .Ellowable minimum of 90 07o. With this minimum he earth fault current could be 3.510 higher than :hrce-phase symmetrical fault current. Since every made to keep the negative phase sequence :;•:..Llarice as near as possible to the positive value, .::.d since in practice earth fault currents rarely achieve or full prospective value, it is normal within power - . .;:ion design to assume that the unrestricted earth Huh ..urrent is the same as the three-phase symmetrical The fault levels associated with internal systems u .L follows: • Ii
v
• 3.11 kV • 415 v
750 MVA (break) 250 MVA
— 31 MVA
39.4 kA = 43.7 kA
= 43.1 kA
\..1.:rdl earthing resistors (NER) are provided on the I kV and 3.3 kV systems which limit the fault current pproximately 1000 A per infeed. However, the -lc heN±,stem is solidly bonded to earth to make availfull prospective fault current to allow proper .
d
clearance of fuses. The maximum current returning to an internal system neutral under a single earth fault condition is therefore that associated with the 415 V system, and this fixes the size of the station earth network for internal faults. There is a very low probability of the NER flashing over, allowing unrestricted earth fault current to flow for 11 kV and 3.3 kV system faults. If this were to occur on the 3.3 kV system, the fault current flowing through the station earth network would be greater than the design value associated with the 415 V system. The increase in fault current would however be so marginal that the integrity of the station earth system would not be threatened. For outbuildings which do not directly form part of the main station earth network, the size of its earth ring will be dependent on the system voltage and fault levels for equipment within that building. For faults on internal systems, the allowable rise of earth potential should be that appropriate to overcurrent protection as defined in Section 11.2.2 of this chapter. This means that the rise of earth potential should be limited to 430 V for faults cleared in less than 0.46 seconds and 55 V for longer clearance times. Where these limits cannot he economically achieved, special measures (such as local bonding to give immunity from transferred potentials) can be used as discussed later in this section. For these internal faults, 555
Cabling the rise of earth potential at the faulted equipment is taken to be the product of the impedance of the metallic bonding system path and the total earth fault current. To keep the potential gradient across the station to a minimum, the impedance of the fault current return path must also be kept to a minimum. Furthermore, to reduce the risk of electrical interference in control and instrumentation circuits, it is desirable to keep the fault current supply and return paths as close as possible. For rnulticore power cables these aims are achieved by using the armour as the main earth return path. For single-core cables which have their armours
single point bonded, these requirements can best be achieved by running an earth cable in close proximity with the power cables. In the case of large transformer feeds and interconnectors, the single-core cable circuits will be short or will follow a major cable route where an earth cable forming part of the station earth network will already exist in close proximity. However, for motors fed by single-core cables, there is not likely to be an existing earth cable in close proximity to the power cables for the entire length of the route and, in these cases, it is necessary to provide an earth cable between the supply switchgear and the motor terminal. This earth cable is run in close proximity to its associated motor single-core cables. For 11 kV and 3.3 kV plant, the 430 V and 55 V rise of earth potential criteria may not both be met. The possibility of transferred zero earth potential, via structural steelwork or adjacent electrical plant with its own earth return connection, cannot be ignored. Therefore, where paths exist for such 'transferred potentials, immunity must be given. This immunity is provided in these specific cases by installing local bonding between all adjacent plant and between plant and steelwork to which personnel may make simultaneous contact. Alternatively if there is a station earth bar connection point locally, the plant may be bonded to this. For 415 V fuse-protected circuits the rise of earth potential under earth fault conditions will be in excess of 55 V and therefore local bonding may be necessary dependent on the protection clearance time. As shown in Section 4 of this chapter for motor circuits, the fuse size is selected for starting conditions rather than full-load current and is therefore relatively large. This means that to keep the conductor/armour loop resistance to a sufficiently low value to clear an earth fault in less than 0.46 seconds, the cable route length would have to be severely restricted or the cable size would have to be substantially increased. In this situation the economic solution is to provide local bonding on 415 V motors in a manner similar to that for I I kV and 3.3 kV circuits, to give immunity from transferred potentials. However, for feeder circuits other than those for motors, the fuse size will be more closely matched to the cable and therefore it is considered more economic to ensure that the pro-
556
Chapter 6 tection operates in less than 0.46 seconds than t o provide local bonding. In making this judgement, account has been taken of the cost and difficulty of providing local bonding on all small plant such a s switches and light fittings. To ensure that the protectio n operates within the required time limit, the conductor/ armour loop resistance is controlled as detailed i n Section 4 of this chapter. For remote outbuildings which are well outside th e area covered by the main earth electrode system, such as might be the case for a CW pumphouse, there i s some advantage in installing local earth electrodes. Normally a pair of electrodes should be provided t o enable one to be disconnected for testing with the station operational. These electrodes will assist in reducing the rise of earth potential and hence transferred, touch and step potentials. 11.3.3 Lightning protection
As discussed in Section 12 of this chapter, it is necessary to connect the lightning protection system to the station earth network. The details of the required connections are also given in Section 12. 11.3.4 Additional considerations
The requirements of British Standard code of practice CP1013: 1965 should be complied with by earthing each of the following: • The neutral points of each separate voltage ,istem. • Apparatus frameworks and other non-cur carrying metalwork associated with each syst , e.g., transformer tanks and the armours of pow. Ales. • Extraneous metalwork not associated with power systems, e.g., boundary and transformer fences.
11.4
Earth electrodes
The purpose of this section is to give a worked example for sizing an earth electrode system using the principles already given in Section 11.3.1 of this chapter. During this process, alternative types of electrodes
are assessed for their suitability for power station applications. The types of electrode investigated are as follows: • Sheet steel piles. • Cylindrical steel piles. • Vertical earth rods.
• Buried horizontal strip. The calculations show that a considerable length of buried strip or a large number of earth rods would be required to dissipate the fault currents associated with
Earthing systems .hiv svstems. Therefore, these types of electrodes oire considerable space and are difficult to accomrc wdate at the locations where EHV system faults are i.e., generator or station transformers. to occur, :therefore more convenient to use sheet or cylin.1, tcel piles which form a more compact electrode. type of steel pile used for the earth elecstation will usually be selected from new Je thatathe civil contractor has on site for his own
90mm DUCTS AS REQUIRED
E
1 ---MC 1
—
A 4
A
Foil calculations to obtain the overall station re.;,:.ince and rise of earth potential are only cornfor steel piles to demonstrate the principles. The parameters selected for all examples are as 11 0v.s: i„,i m urn earth fault current to return to remote • \ncuirals is 28 kA. It should be noted that this is which has to return to the remote neuhe current the earth electrode and therefore 'on site' :rdl via is ignored. For earth electrode design :eneration this earth fault current is assumed to have curposes, duration of I second. .1 maximum :0
• v.craa soil resistivity to a depth of 10 m at any rroposeci electrode location is 19.9 Sim. I 1 implicity, all calculations are carried out assum:'..z ihe top of the electrode is flush with the ground -tirlai:e. In practice, for steel piles, the top of the .•.....Arode is approximately 1 m below the surface as
,: ; ,m I) in Figs 6.124 and 6.125. The errors from this :; TroNimation are considered negligible, bearing in ihe limitations in the accuracy of soil resistivity
114,1
100mm • I2mm
1
L_
ELECT CONTINUITY STRAPS AT EACH FILE JOINT
11
‘I 7
LARSON NO 3 —I- 4 SHEET PILES li ,I
100mm 42mm STEEL STRAPS WELDED TO PILES WITH CONTINUOUS FILLET WELD -..44111
411111Noil.:Orn
V\
247mm
7--74! . *
1
1200mm
Sheet steel piles
SECTION B-B
Li:, example
is based on Larson No 3 piles as shown :. IL 6.124. This type of pile is trough - shaped, the being 145 mm long and the bottom 248 mm wide; :lliekness of the pile is 14 mm. on,ider the station electrode arrangement shown I 6.122, where %ite measurements have shown the a%.erage soil resistivity for any proposed main
....!rode location to he 19.9 Sim. This figure can be to determine the smallest electrode area capable ' dmipaiing the assumed 28 kA earth fault current . , e.ated with the 400 kV system. discussed in CP1013: 1965, the little experimen,,
Hl ork % , .hich has been carried out on current loading been confined to model tests with spherical elecin clay or loam of low resistivity. One of the --'1',uRe conclusions from this work is that the time - tliture on short-term overload is inversely prot;onal to the specific loading, which is given by %there i is the current density at the electrode
•,, •
and Q the resistivity of the soil. For soils inmaximum permissible current density is
ated the
2 00 mm 5-..1,1
ALuMifflu1,1 EARTH BAR
FIG. 6.124 Arrangement of sheet steel pile electrode
i=
I 57.66 x 10 6
\I
Qt
A/m 2
where: Q = soil resisitivity, Sim t = duration of fault, s
For the given conditions:
=
57.66 x 10 6
A/m 2
19.9 x 1
i = 0.17 x 10 4
A/m 2 557
Cabling
Chapter 6 1SOmm MIN
90m, CABLE DUCTS AS REOLAPEO
1000mm SO
I 41:11) mm 100mm 12m1n ALUMINIUM EARTH BAR
701)mm
BOLTED I GOITrri 12mrn ALUMINIUM BRACKET SEMCNABLE FOR TEST PURPOSES
STEEL BARS WELDED 1 04,1rorn r 12rr.rn STEEL
EXTENSIONS WELDED TO PILE LINER
TOP OF CYLINDRICAL STEEL ELECTRODE
65Ernm MIN LENGTH OF roew
LL SECTION A-A
FIG. 6.125 Arrangement of cylindrical steel pile electrode
Minimum length of single pile required: L
1 i x (2w
s = length of side of pile, m 4s)
where 1 = earth fault current, A = maximum permissible current density, A/m 2 558
w = width of base of pile, m
28 000 4
0.17 x 10 x ((2 x 0.248) + (4 x 0.145)) L = 15,3 m
Earthing systems 'co" for the pile electrode under consideration, the the equivalent hemisphere is: 01
10
For an earth fault duration of 1 second and a soil resistivity of 19.9 fl m, the maxirnurn permissible rod loading is:
= 3.0 m
380
i
I0gn
10
L
The total length of earth rod required for a fault current of 28 kA is:
in
3.0 - = 0.3
L -
28 000
%.fore, for two pile electrodes in parallel: 1+a ,_ ( --.
x (resistance of a single pile)
I + 0.3 ) (
= =
1
--
2
1
x 1.06
0.69 C2
three pile electrodes, arranged in a triangle:
( 1 + 2a,
x (resistance of a single pile)
- 329 m
85
10
[Z2
-85 A/m
\(19.9 x 1)
Assuming that the maximum depth to which an earth rod can be driven is 5 m, the total number of rods required is 66. In order to obtain reasonable current dissipation and overall resistance from the electrode array, the rods should be spaced on 3 m centres. Using this spacing, an area of some 600 m 2 is required for the electrode array. In view of the need to place the electrode close to the location where an EHV earth fault may occur, e.g., generator transformer, it is likely to be difficult to find such an area of free space available. A further complication with this type of electrode is the difficulty of interconnecting the large number of rods with buried cable or strip. This type of electrode is not therefore recommended for power station applications.
3 11.4.4 Earth strip
( + 0.6 )
x 1.06
3 R; = 0.56 C2
This section is based on the use of 50 x 6 mm copper strip. For an earth fault duration of 1 second and a soil resistivity of 19.9 12m, the permissible current rating is once again: = V 57.66 x 10 6
(his it can be seen that only a relatively small :t rrmement in resistance is obtained by adding the electrode. Therefore, if ground conditions permit, • 1;,1 ■,- be more beneficial to drive two electrodes to ater depth than to add further electrodes. ftc o‘erall station earth resistance and rise of earth are then determined in the same manner as rii
•
19.9 x 1
- 0.17 x 10 4 A/m 2
Total length of strip required is: L
fault current -
current density x circumference
11.4.1 of this chapter. 28 000 4
11.4.3 Earth rods
0.17 x 10 x [(2 x 0.05) + (2 x 0.006)]
,
ection is based on the use of 16 mm diameter .vensible steel-cored copper earth rods complying with
= 147 m
Standard 43-94. ihe general formula for permissible current loading al he transformed by using the surface area of a 16 min earth rod to yield the following:
=
380
./(Qt)
A/m of earth rod
In order to obtain reasonable current dissipation and obtain the required order of resistance, this tape would need to be buried over an area in excess of 300 m 2 . As discussed for earth rods, this amount of free space is not normally available at the required location. An alternative would be to install the electrode in contact with the earth under the foundation slab concrete. 561
Cabling
Chapter 6
However, this would require accurate planning so as not to delay the civil contractor and if any damage occurred during concrete pouring this could not be detected. An added complication is the time involved in making an electrical connection between the strips at each mesh intersection.
NOMiNAL iNSULATICN TO PREVENT ELECTRICAL CONTACT ANO CORROSION
11.5 Earth network construction and plant bonding Earth networks are formed and bonding of plant is carried out using PVC insulated cables. Earth cables run
on the power cable supporting steelwork are considered to give a more economic installation than copper or aluminium bar clipped to the building surface. The use of earth cables allows the same installation and termination techniques as for power cables, giving a unified approach to labour requirements and the use of standard tools and equipment. All cables used for earthing and bonding comply with the insulation, construction and testing requirements given in 3S6004: 1975. The cables may have either green or green/yellow insulation and the following rationalised range of sizes is used: Size,
111171 2
Type of construction
2.5
Stranded copper/PVC
4
Stranded copper/PVC
6
Stranded copper/PVC
10
Stranded copper/PVC
16
Solid aluminium/PVC
35
Solid aluminium/PVC
95
Solid aluminium/PVC
150
Solid aluminium/PVC
300
Solid aluminium/PVC
500
Stranded aluminium/PVC
All earth cables are terminated, bolted to equipment and where necessary protected from corrosion using the techniques given in Section 9.2 of this chapter. 11.5.1 Main earth network
The main earth network is formed by interconnecting the earth electrodes and forming rings around main plant areas as shown in Fig 6.122. These rings are extended into all levels of the building where major plant is located. Interconnections are made using 'teeoff' bars of the type shown in Fig 6.126. These `tee-off" bars are also inserted in the ring at strategic locations to enable connections to be made to electrical plant. As discussed in Section 11.3 of this chapter, the largest current that the station earth network will normally have to carry is the 43.1 kA associated with the 415 V system. Major plant such as switchgear is 562
0
0
0 0
_
FIG. 6.126 Arrangement of tee-off connections
given a 3 -second rating and it is considered appr o , priate to give this rating to the main earth network. However, this fault duration is considerably in excess of that associated with back-up protection and such faults must be considered extremely rare. Under these circumstances it is considered acceptable to allow the earth cable to reach a final temperature of 325 ° C, as allowed by Engineering Recommendation S5/1 for aluminium bar. Whilst this ensures mechanical integrity of the earth system, it will be appreciated that the PVC cable sheathing will disintegrate and any affected cables would have to be replaced. However, for fault durations appropriate to back-up protection, the earth network should not be damaged and therefore the final conductor temperature of earth cables is limited to 160 ° C. The required cable size is calculated using the formula given in Section 4.3.1 of this chapter: 1 S = _
K V log r, ROr 43 100 V 148
,3)/(0;
f3)] 3
log s [(325 + 228)/(25 + 228)]
= 570 mm 2 The use of 500 mm 2 cable is accepted as being adequate for forming the station earth network because of the extremely low probability of a 3-second fault and also, since the network is a ring, there will be a degree of current sharing between cables. For a cable temperature limit of 160 ° C the maximum allowable fault duration is 1.26 seconds which is adequate to cater for back-up protection. 11.5.2 Instrument earth network
To reduce the risk of interference on control and instrumentation equipment, a 'clean' earth termed th e station instrument earth is provided. This instrumegt
Earthing systems discussed in Section 11.6.1 of this chapter, the which a pile may economically be driven is jcl , t h w Jwcricient on the ground conditions. For this example, um economic length of pile is assumed to . Therefore Nvo interlocked steel piles will be 10 m to dissipate the current. ujred ,4age is to assess the current carrying caiie of1e1 ihe electrode material itself and the con-„.H11; to it. Using the short-circuit formula given '-;ection 4.3 l of this chapter, the minimum crossarea of steel to carry the earth fault current is ,,ieu hated
csa = 4 (9 x 97) = 3492 mm 2 This allows a significant factor of safety on the minimum requirement of 372 mm 2 . Now the electrode resistance can be determined using the formula given in CP 1013: 1965 for plate electrodes: R=—x — 4
A
where Q = soil resistivity, Om
as follows:
A = surface area of electrode, m
( Of + )
S
19.9
R–
Iogn
+
FOr
= 1.90
for 1 = 28 000 A, t = 1 s, Of
°
375 C and
25°C;
28 000
log,
78
( 375 + 202 ) 25 + 202
S = 372 mm
V [(2 x 0.248) + (4 x 0.145)1 x 10 x 2
4
eel: K = 78 and /3 = 202
5=
To avoid an excessive rise of earth potential, an overall station resistance typically of less than 0.1 0 is required. Therefore, even with the eight proposed electrodes in parallel, an individual electrode resistance of 1.9 0 is not acceptable and the number of pile sections must be increased. Increasing the number of pile sections to 25 would result in an electrode 10 m long having a resistance of:
2
considering the electrode itself, the total cross-,: uional area for two steel piles is: = 2 x 14 x [248 + (2 x 145)] = 15 064 mm 2 llov,e\.er, allowance has to be made for surface corro,ion of the electrode over the life of the station. 1:1:‘, will depend on a number of factors of which the , ,ignificant is the soil pH which should be es:,,h1Hhed from soil surveys. For this example, it is as•11111Cd that the corrosion reduces the electrode thickness h, 3 mm (1.5 mm per surface) over the station life. I here rore after corrosion the cross-sectional area of ,N o piles is:
R=
19.9 4
V [(2 x 0.248) + (4 x 0.145)1 x 10 x 25
The resistance of the remaining electrodes is then calculated assuming the same number of pile sections but using the soil resistivity appropriate to the location. For the purpose of this example let us assume that the remaining primary electrodes have resistances of 0.41, 0.51 and 0.49 0, and the secondary electrodes have resistances of 0.50, 0.58, 0.45 and 0.62 0. The overall station resistance is given by: ( 1 R1
It can be seen that this is considerably in excess of !Ile required 372 mm 2
. With respect to the connections from the earth cable , Litmection bar down to the earth electrode, it is normal practice to use four 100 x 12 mm steel bars (as , , hom,ri in Fig 6.124) to provide adequate mechanical trength. Again assuming 1.5 mm of surface corrosion L)N•er the station life, the final cross-sectional area will
7r
= 0.54
---- 2 x 11 x [248 + (2 x 145)] = 11 836 mm 2
he:
2
R=
(
1
1
R2
Rn
1
1
1
1
1
0.54
0.41
0.51
0.49
0.50
1
1
1
0.58
0.45
0.62
y
R = 0.063 0 559
Cabling
Chapter 6
Now assuming that the power station under consideration is some 3 km from the 400 kV substation, as mentioned in Section 11.3.1 of this chapter, it should be assumed that 30wo of the earth fault current returns via the ground. The rise of earth potential (REP) at the power station will therefore be:
previously in Section 11.4.1. With respect to the c on , nections to the pile, four 100 x 12 mm steel bars are
used as shown in Fig 6.125, these being shown t o b e of adequate size in Section 11.4.1. The resistance of a vertical rod type electrode can be obtained using the following formula given by Tag g [29]:
REP = 28 000 x 0.3 x 0.063 = 529 V
R This figure of 529 V is lower than the acceptance criteria of 650 V and gives a reasonable factor of safety.
fc)/27r1_,] x [log, (8L/d)
1]
where Q = soil resistivity, Qm L = length of rod, m d = diameter of rod, m
11.4.2 Cylindrical steel piles This example is based on a typical cylindrical pile having an external diameter of 1.05 m and a radial thickness of 6 mm. A typical arrangement is shown in Fig 6.125. Reference should be made to Section 11.4.1 of this chapter for explanation of formulae and definitions where they are not given in this section. Maximum allowable current density:
=
57.66 x 10 6 Q
57.66 x 10 6 V19.9 x 1
t
= 0.17 x 10 4 A/m 2
2x
x [log, (8 x 10/1.05) — 1]
r X 10
= 1 06 0 As discussed previously in Section 11.4.1, a value of resistance of 1.06 0 is considered too large for a mai n electrode. It will therefore be necessary to incredse the electrode length or put a number of electrodes in parallel. The following method of dealing with electrodes in parallel is given by Tagg [291 The method uses the 'equivalent hemisphere' principle where the rod electrode is replaced by a hemisphere having the same
resistance. The radius of this equivalent hemisphere is given by:
Minimum length of pile required:
r = Li[log n (8L/d) — 11
L
i xrxd
where L = length of rod, m
where d = external diameter of pile
L—
19.9
R
28 000 0.17 x 10 x r x 1.05 4
d = diameter of rod, m
— 5.0 rri
Although the minimum length required for current dissipation is 5 m, it is proposed that a 10 m length be used to obtain a lower value of resistance. Now considering the current carrying capability of the electrode material itself and the connections to
Maximum csa of pile = r(R — r ) 2
2
2
For two rods in parallel: Resistance of rods in parallel
1+a
Resistance of one rod
2
where a = r/S and S = spacing of electrodes, m And for three rods in parallel, arranged in a triangle: Resistance of rods in parallel
1 + 2a
Resistance of one rod
3
2
r(525 — 519 ) = 19 679 mm 2 After corrosion csa of pile = r(523.5 2 — 520.5 2 ) = 9839 mm 2 This can be seen to be considerably in excess of the minimum requirement of 372 mm 2 that was derived 560
From the above formulae it can be seen that as the spacing S increases, a will tend to zero and the ideal, value of 0.5 for the ratio will be approached. However whilst initial increases in the spacing give a good improvement in the ratio, very large spacings would be required to approach the ideal value. For practical purposes, setting the spacing equal to the rod length normally gives an acceptable design.
Earthing systems ork is normally installed in the main control L'arth area where the bulk of C and I equipment is Ifil'ated. The instrument earth network is connected, , le point, to a relatively noise-free part of c in earth system. The reason for using a single aioii oid circulating earth currents or is [o a \.. earth fault currents flowing in the system which result in interference. instrument earth is distributed to all C and I [Iii equirmient, marshalling cubicles, local adapter using a combination of earth cables and the ek2.. tnultipair cables. A general arrangement of is shown in Fig 6.127. It can be seen from H figure that the screens of multipair cables are , ..vonected to the instrument earth at a single point. To interference to a minimum, it is preferred that ep •he oN,olt rail(s) of internally-generated power supplies connected to the instrument earth. The PAX and jp,v (direct wire) telephone systems should also be _onnected to the instrument earth network. It should be noted that the armours of rnultipair and nIticore cables are not connected to the instrument . network, but single-point bonded to the station ,trth network. The reasons for this are twofold. Firstly, c 'here is a risk of cable armours becoming accidentally ,hortecl to equipment cases and if the armour were „innected to the instrument earth this would defeat he single earth point connection policy for that system. '.‘2,..ondly, many multicore cables emanate from switchlocal panels where an instrument earth will not ter readily available and therefore it is more convenient 11,1 cheaper to use station earth.
and other major plant are sized for a 3-second rating with a final conductor temperature of 325 ° C. The bonds for all other power plant are sized for back-up protection which is typically up to 1-second rating. For 11 kV and 3.3 kV systems, the earth fault current is normally restricted to 1000 A per infeed which would result in a relatively small bond size. However, it is considered prudent to ensure mechanical integrity in the event of a neutral earthing resistor itself haying a short-circuit. Under these circumstances of a doublefault, i.e., both main protection and neutral earthing resistor failing, some damage to the PVC cable sheath is accepted and the cables are sized for 1-second rating with a final temperature of 325 ° C. On the 415 V system, the earth fault current is not restricted and therefore the earth cables are sized for 1-second rating with a final conductor temperature of 160 ° C, to ensure they are not damaged for faults cleared by back-up protection. For fuse-protected circuits it is traditional to use an earth bond size of not less than half the phase conductor size. In all cases the minimum bond size allowed is 4 mm 2 to ensure mechanical integrity. The bond sizes for these conditions are calculated as follows, using the formula given in Section 4.3.1 of this chapter. It should be noted that, for economic reasons, the calculated value has been reduced down to the nearest cable size. This is particularly the case for 3-second ratings because in practice this fault duration is unlikely ever to be reached. (a)
II kV, 750 MVA system
115.3 Earth bond cable sizes
For aluminium cables, constant K = 148 and 13 = 228
mn the same basis as that already discussed for the .11,iin network earth cables, the bonds to switchgear
Therefore, for a short-circuit duration of 3 seconds:
Flo. 6.127 Single-point earthing system for C and I cables 563
Cabling
Chapter 6
S — K
For motors, other plant and cable gland bo n d s where a 1-second rating is required, a 300 rn ni z cable is used. Alternatively, for cable gland bond s, aluminium bar having the same cross-sectional area may be used.
lov r, [(Or + 0)/(0, + i3)]
39 400
3
148
log„ 0325 + 228025 + 228)]
(c) 415 V, 31 MVA system
= 521 mm 2
S—
148
3
Therefore, for a short-circuit duration of 3 seconds and a final conductor temperature of 325 ° C:
For a short-circuit duration of 1-second:
39 400 .\/
For aluminium cables, constant K -= 148 and = 228
1
43 100
S
,\,/
148
V log o [(325 + 228)/(25 + 228)]
3
log i, [(325 + 228)/(25 + 228)]
= 570 mm 2
= 301 mm 2 For the 3-second rating, the nearest rationalised cable size of 500 mm 2 is selected to bond plant. For switchgear the 3-second rating is met by using
two 300 mm 2 cables, one connected to each end of the switchgear earth bar. For motors, other plant and cable gland bonds where a I-second rating is required, a 300 mm 2 earth cable is used. Alternatively, for cable gland bonds, aluminium bar having the same crosssectional area may be used. (b) 3.3 kV, 250 MVA system For aluminium cables, constant I< = 148 and 228
For a short-circuit duration of 1-second and a final conductor temperature of 160 ° C:
S—
148
1
log, [(160 + 228)/(25 + 228)1
= 445 mm 2 For a short-circuit duration of 1-second and a final conductor temperature of 325 ° C:
0 = s=
Therefore, for a short-circuit duration seconds:
43 100 V
of 3
43 100 V 148
log o [(325 + 228)/(25 + 228)1
= 329 mm 2 43 700
\i/
3
—
148
log o [(325 + 228)/(25 + 228)]
= 578 mm 2 For a short - circuit duration of 1 - second:
43 700
I
\
148
log e [(325 + 228)/(25 + 228)]
= 334 mm 2 For the 3-second rating, the nearest rationalised cable size of 500 mm 2 is selected to bond plant. For switchgear, the 3 - second rating is met by using two 300 mm 2 cables, one connected to each end of the switchgear earth bar. 564
For the 3-second rating, the nearest rationalised cable size of 500 mm 2 is selected to bond plant. For switchgear the 3-second rating is met by using two 300 mm 2 earth cables, one connected to each end of the
switchgear earth bar. For motors and other plant where a 1 - second rating is required, a 500 mm 2 earth cable is used. For cable gland bonds, aluminium bar should be used and since this can be operated at 325 ° C without harm, the crosssectional area required is 300 mm 2 . 11.5.4 Plant bonding arrangements
This section gives specific plant bonding arrangements which are based, where appropriate, on the fault levels and calculated cable sizes given in the previous Sub section. Plant bonding arrangements for electrical system neutral earthing are as follows:
Earthing systems mer neutral earthing The genGenerator transfor m transformer HV neutral connection should • cra E of an earth cable connected from the earthy ,: ori ,i s of the neutral CT direct to the adjacent generator electrode. The cable size is to be :Faw,fortner earth full 400 kV earth fault current _11,:ulaJed using the generation) for a fault duration i„ding, on-site L.r
•
,:
and unit transformer neutral earthing The unit transformer LV neutral earthing and 2 shall be a 500 mm earth cable, con,. onneL:tions the transformer neutral earthing rers:c[ed from onto the local earth network. .1,tors
•
The 3.3 kV A transformer neutral earthing :-.insformer neutral earth connections should be by 2 earth cable connected from the means of a 500 mm neutral earthing resistors, either direct [rar4ormer adjacent earth electrode or to the station earth to an uetwork, v,hichever is the nearer.
The 415 V • 4i5 V transformer neutral earthing ansformer neutrals should be connected to earth ;r he 415 V switchgear, a connection being made , ,:: -ect) the switchgear neutral and earth bars via a !i nk. i'lint bonding arrangements for earth connections to
plant are as follows: • Generator earth bond network The generator earth bond network consists of an earth bar mounted ;II parallel with the main generator connections to miich all items of plant operating at generator ‘oltage are bonded. This earth bar is connected to arth at the generator transformer earth electrode Li•i u two 500 mm 2 earth cables. • Sration transformers The earth terminals of these iransformers are connected to the station earth net'ark by means of a 500 mm 2 earth cable.
• II 3.3 kV ancillary transformers The earth teriiinals of the ancillary transformers are connected to !he station earth network by means of a 500 mm 2 earth cable.
• Gas
turbine generator stator, VT cubicle and liquid wurral earthing resistor These items of plant are
onnected direct to the station earth network by means of a 500 mm 2 earth cable.
• likV switchgear
The earth bar of 11 kV switchfear is connected to the main station earth network l)!, means of two 300 mm 2 earth cables, one cable 1,emg connected to each end of the bar.
• 1 I kl / motors
The earth terminals of 11 kV motors
are connected to the 11 kV switchgear earth bar by
means of 300 mm 2 cable, the cable being routed ith the II kV power cables.
In addition, a 150 mm 2 bond is to be provided between the motor and adjacent plant and structural (or other) steelwork to which personnel may make simultaneous contact. • II kV/415 V gas turbine unit transformers The earth terminals of these transformers are connected to the station earth network by means of a 500 mm 2 earth cable. • 3.3 kV switchgear For switchgear connected to a transformer and not fuse-protected, the switchgear earth bar is connected to the main station earth
network by two 300 mm 2 earth cables, one connected to each end of the bar. For switchgear fed by fuse protected cables, the power cable armours will be utilised to provide the earth return path. A cable gland bond, of crosssection not less than half that of the power cable core, being provided between the gland and the switchgear earth bar with the exception of single-core power cables which utilise a 300 mm 2 bond. • 3.3 kV motors For 3.3 kV motors fed by three single-core power cables, an earth return cable of 300 mm 2 cross-section is provided from the motor earth terminal to the supply switchgear earth bar. The earth cable should be laid in proximity to the power cables.. When the motor is fed by a multicore cable, the cable armour is utilised to provide the earth return path, connection being trade to the cable armour from the motor earth terminal by a bond of crosssection not less than half that of the power cable core. In addition, local bonding is provided between the motor earth terminal and adjacent plant, and structural or other . steelwork to which personnel may make simultaneous contact. The size of bond shall be half that of the power cable core cross-sectional area. th--e 3.3 kV diesel generator stator frame is connected to the station earth network by means of a 500 mm 2 earth cable.
• 3.3 kV diesel generators
• 3.3 kV diesel generator harmonic suppressors If harmonic suppressors are provided on the 3.3 kV diesel generators, their tanks are to be connected to the station earth network by means of a 500 mm earth cable. • 3.3 kV diesel generator neutral earthing resistors
The 3.3 kV diesel generator liquid earthing resistor tanks are to be bonded to the station earth network by means of a 500 mm 2 earth cable. • 415 V switchgear For switchgear fed by single-core cables, the switchgear earth bar is connected to the 2 main earth network by means of two 300 mm cables, one connected to each end of the bar. For switchgear fed by fuse-protected multicore cables, the power cable armouring is utilised to pro565
Cabling vide the earth return path. A cable gland bond of cross-section not less than half that of the power cable core is provided between the gland and switchgear earth bar.
• Transformers having 415 V low voltage windings Transformers of 1 MVA rating and larger have a 500 mm 2 cable connection between the transformer earth terminal and the 415 V switchgear earth bar. Transformers of rating in the range 0.5 to 0.8 :VI VA have a similar connection of 300 mm 2 crosssection. Transformers of rating less than 0.5 MVA have a si milar connection of cross-section not less than one half that of the power cable core. • 415 V plant other than switchgear and transformers For plant within this range fed by a multicore cable the cable armour shall be utilised as the earth return. The gland bond size between the plant and the gland shall be of cross-section not less than half that of the power cable core, with a minimum cross-section of 4 mm 2 . When the plant is fed by single-core cables, an earth return cable of 300 mm 2 cross-section shall be provided from the equipment earth terminal to the supply switchgear earth bar. The earth cable shall be laid in close proximity to the single core power cables. Any plant which is fed by a conduit or trunking system shall also have an earth cable included in the conduit of the same cross-section as that given by the above criteria. For motor circuits of 1.5 kW and above, additional local bonding is provided between the motor and adjacent plant and structural or other steelwork to which personnel may make simultaneous contact. The bond size should not be less than half that of the power cable core, with a minimum size of 4 mm 2 . • Control and instrumentation marshalling boxes and cubicles The steelwork of all panels, marshalling )oxes and the like should be bonded to the station earth network using 4 mm 2 earth cable. Where equipment is mounted directly onto earthed metalwork, no bond is necessary. Where a power cable is taken into a panel, the cable armour is bonded to the panel and a separate bond to the station earth network is not required. Plant bonding arrangements for insulated cable glands of the type described in Section 9.1 of this chapter are normally used for both power and control cables. This means that where a connection is required to the cable armour, a bond has to be connected from the gland integral earth tag to the equipment earth bar/stud or other glands as appropriate. In order to , pass this information to site, a series of bond codes is used. The gland bond codes are recorded on the block cable dia566
Chapter 6 grams and also on cable schedules and work cards used on site. A list of typical bonding codes is as follows: • 11 kV, 3.3 kV, 415 V power cables and multicore control cables Earthed:
A
The armour is connected to th e station earth or, where applicable, the equipment earth stud.
Floating:
B
The armour is insulated from earth. If the cable has a screen then this also is insulated. An insulating shroud is fitted over the gland body.
• Multipair cables Earthed:
H The armour is connected to the station earth system and the cable screen is connected to the instrument earth system. F In situations such as outbuilding control panels where a separate instrument earth system is not available, both armour and screen are connected to station earth.
Floating:
B
The armour is insulated from earth. If the cable has a screen then this also is insulated. An insulated shroud is fitted over the gland body.
P The armour of 'digital control cables' is connected to the armours of other cables of the same discipline in the same box. The cable screen is connected to the screens of other cables of the same discipline in the same box. R
The armour of 'analogue control cables' is connected to the armours of other cables of the same discipline in the same box. The cable screen is connected to the screens of other cables of the same discipline in the same box.
S
Special requirement. To obtain the correct bonding information refer to the block cable diagram.
Actuator cables: / The armours of the actuator cables (composite power/control design) in the load centre are connected together and to the armour of the incoming multipair cable. The actuator cable outer screen and the incoming multipair cable screen are connected to the insulated screen bar in the load centre. The actuator cable inner screen is connected to station earth.
Earthing systems The actuator cable armour is insulated from earth. The screen of the flexible power and control cables is earthed at the actuator earth stud. Cnarmoured cable and cables requiring no connec• :i
on to armour 0 Stuffing gland Z
No gland.
gland bonding codes that may be
f.ible 6.'6 shows with equipment. A block cable diagram ated
: hc „i ng a typical application of bonding codes for rol and instrumentation cabling is included as Fig , 8. A similar block cable diagram for power cabling 61 — hown in Fig 6.129. of cable gland bond connections should The sizes !-‘,: a , follows: Insulated cable glands for 11 kV cables Where re• quired, the bond for an insulated cable gland should consist of an aluminium bar arranged to provide the shorting strap across all glands of the circuit and the connection to the switchgear earth bar. have a minimum crossThis aluminium bar should 2 ectional area of 300 mm . • Insulated cable glands for 3.3 kV and 415 cables
For single core cable circuits, when required, the bond should consist of aluminium bar arranged to provide a shorting strap across all glands of the circuit and also connect to the switchgear earth bar. this aluminium bar should have a minimum cross, ectional area of 300 mm 2 . For multicore cable circuits, where the cable armouring is utilised as the earth reiurn circuit for he plant, the earth bonds at both ends of the cable shall use an earth cable of cross-section not less :han half that of the power cable core, with a minimum cross-section of 4 mm 2 . • rfmtrol and instrumentation insulated cableglands
\‘ here cable gland earth bonds are required they shall be 4 mm 2 stranded copper earth cables. P'.int bonding arrangements
for extraneous metalwork:
▪ Bonding of structural steelwork
All major vertical structural steelwork shall be bonded together and to the main earth network "oh a 300 mm 2 cable. The connection to each steel Lolumn is made via a suitable connecting lug which hould be welded to the appropriate steel columns under the main steelwork contract. The interconnections between columns is carried on the cladding support steelwork or other adjacent steelwork. Connections to the earth electrodes should be made dr all locations where the steelwork bonds pass an earth electrode position. ,
teel columns of the
• Bonding of cable supporting steelwork
In locations where cable support steelwork is directly connected to the station structural steelwork no additional bonding is required. Where, however, cable support steelwork is insulated from the station steelwork (e.g., concrete cable tunnels) the steelwork should be bonded direct to the main station earth network. This connection is made onto every section of insulated steelwork using any convenient station earth network cable being carried on that section of steelwork. In cases where there is no earth cable on the section of steelwork, a separate earth cable of 35 mm 2 cross-section shall be used, this cable being connected into the nearest adjacent section of earth network.
• Bonding of station perimeter fences
Perimeter fences are connected to earth by means of separate earth
rods driven at all corners and at intervals not exceeding 100 m around the fence. The connection to the fence is made with a 10 mm 2 stranded-copper earth cable. • Bonding of electrical plant compound fences
Electrical plant compound fences shall be connected to earth as for station perimeter fences and, in addition, a separate connection shall be made from the fence to the main earth network associated with the plant in the compound. This connection shall be a 10 mm 2 earth cable.
11.6 Testing 11.6.1 Earth resistivity measurement
The method of soil resistivity measurement most commonly used is that derived by Dr. F. Wenner [301, In practice the method uses four electrodes driven into the ground in a straight line with equidistant spacing 'a' as illustrated in Fig 6.130. To obtain accurate results it . is important that the electrode depth does not exceed one twentieth of the electrode spacing 'a'. The outer two electrodes are used to circulate current and the inner two measure the ground potential difference. This is carried out using an earth tester which has the appropriate four terminals for connection to the electrodes and gives a direct reading in ohms. Assuming the soil to he homogeneous the value of soil resistivity is given by: Q=
IiraR
where R is the resistance measured by the instrument If the distance 'a' is increased, the current will penetrate deeper into the ground and the measured value of resistivity will be related to this greater depth. To access the resistivity at various depths, a series of measurements are taken with increased electrode spacings 567
Cabling
Chapter 6 TABLE 6.26 Gland bonding codes relative to equipment
Equipment
11 33
kV kV
Bonding code Q -t
Switchgear
Cables
415 V
Interconnections between switchboards
11
kV
3.3 kV (e.g., Unit 1 and Unit 2)
415
V
Multicore
Motors
II
kV
3.3 kV 415 Transformers
Ii
V kV
Multicore 3.3 kV
A at Unit 1
B at Unit 2 A at Unit 1 B at Unit 2 A at Unit 1 B at Unit 2 A at Unit 1 B at Unit 2 B A/B * A/B 4. B B A/B *
415
V
A/B *
Distribution boards
415
V
A
Equipment fed from distribution boards
415
V
A
Plant-mounted transmitters (pressure switches, limit switches, transducers, etc.)
Multipair Multicore
B B
Network marshalling boxes
Multipair
R, P or S
Network marshalling cubicles, (except control room unit and transmission marshalling cubicles)
Multipair Multicore
R, P or S B
Control room unit and transmission marshalling cubicles, (except transmission end of interconnections between them)
Multipair
H
Transmission marshalling cubicle ends of interconnections to control room unit marshalling cubicles
Multipair
B
Control room panels and desks
Multipair
B
Interlock cubicles
Multicore
A
* See Fig 6.129
568
-.
Multicore
•■ •
L
r
c;
-14
LIOlik. AN. XI MAHSMAtLfr C WC,
ANBL OUBALLE
c
t
. L. AHEM BC. .0 OW BYLLar,
7 IV., I no,
inv.vy.r..1
....LIAO. BOX .4.14,.../.0.G Eli N CLsSJcLe
s rd. 1 up S r.
110k
1=40 .4 * SWUM
• 4111.1 *
• 41.41, 151140.14.1, BO
r
▪
NI I 5101001,0l..
.015.41.1.114O 004
BOBLB'
onTUOTOIN LOGO CENINt:
0,11019 kAJ.In 6^11
:
: voScuo■ ItU SCONE TI 0001 CE.B-111=1
OVINCLf L0411 Oh I ALA
S....CIK.e MOM,
, cLAIBLL POMO. MOP CON Ifich O.L.LX.BLC.. — T O on100004 N.NIlTn B..0
ER', 6.128 Gland bonding and earthing for control and insiroincitiation cabling
Cur I vok
Sm_nnew
sweisAs butinJeD
.1
likV SWIICHGEAN
... , EAR tH BAH
A
A
SjJ
EARTH CABLE FROM TANK TO SFA FON LARTH
TRANS', MVA
EARTH CABLE FROM TANK 1 0 STATION EARTH
AND
LARGER
TATTER?
(0 , 4r, L.1
I HANSI- OMMER I AMVA AND SMALLER
[ 11AI FiY I USE ROA ti
A 3 Ay SWITCHGEAR
T
A
3 3 KV SW/TCHGEAR
5360 SWITCHGEAR
EARTH OAR
A IdA;
A )
MOTOR LESS THAN 16006W
1VR LY SI L
EAR THRAII
DC SWII rII.L Ali
EARTH BAR
611109,14 :
TRANSFORMER KIVA AND SMALLER
F
TRANS ' 2 MVA
EARTH BAR
MOTOR OVER 1600MY
I N1ERCONNECTOR
4
A
i
/
EARTH BAR
3 AV SW ITCHGE AR
SUPPLIED VIA FUSES)
DC DisiFtibu it/N BOAR()
A 415v SWITCHGEAR EARTH BAR
4101/ SWITCHGEAR
415v Swi I CHGEAR
A 61•I'
A
A pri
1
MON311 UNDER
AO. A
A4
11
.'
A 41 TV SWITCHGEAR ISURRLIED VIA FUSES)
Allt1
EARTH BAR
A
DISTRIBUTION BOARD MOTOR OVER I RK LW
EARTH BAR
9
\— INTERCONNEC TOR
EARTH BAR
A
A
PANEL KEY DISTRIBUTION BOARD 415V
A id' - - - - - - - -
I NSutAl ED GLAND WITH INTEGRAL BONDING CONNEC TOR AND SCALE N E
I NSULATED GLAND WITH INTEGRAL BONDING CONNECTOR A FIT
I NSULATED III AND WITHOUT INTEGRAL BONDING CONNECTOR
---------
Su13-DISTRIBUTION BORRD iSV
SUB-DrS1R/BUIION BOARD 4150 - -
11,711
; INSULATED GLAND WITHOUT INTEGRAL BCNUNG CONNECTOR ULR WI I H ACHE TN IL limiNA FOR
S tAtION EAR HI GLAND BONDINL, CODE S A ARMOUR GUNNEL:7'EO i0 STA] ION EAR fH - ARMOUR rn4SuLA rELI MOM k All III AND SHROUD FIT TED OvLii GlAND ODDY
6.129 Gland bonding and earthing, for power cabling
Earthing systems TABLE 6.27 Soil resistivity measurements
CURRENT SOURCE
Electrode separation (a)
Test Point 'X' R
Apparent resistivity, ft m
aR
FIG. 6.130 Measurement of earth resistivity
lbout the central point. A typical set of measurements Jk en in Table 6.27 and these are shown graphically o Fig 6.131. The next step is to decide the best way to apply these roults. The first step must be to relate the electrode pacing to the effective depth to which the resistivity k measured. CPI013 states that the average resistivity measured is for a depth equal to the electrode spacing. ':ome references will be found quoting the effective J,:nth to be in the range 0.6 to 0.75 times the electrode Spaing. If the soil is reasonably homogeneous, it will he found that the resistivity becomes substantially xnstant with depth as shown in Fig 6.131. The interpretation of effective depth is not critical under these ..onditions and to assume the effective depth is equal to electrode spacing should give acceptable results in practice. The formula used is derived on the assumption that the soil through which the current circulates is homogeneous, and this would be borne out if the soil:-c.istivity remained constant as the electrode spacing
metres
Si
1
5.8
5.8
36.4
2
1.58
3.l6
20.0
3
0.92
2.76
17.3
4
0.68
2.72
17.1
5
0.49
2.45
15.4
6
0.46
2,76
17.3
7
0.43
3.01
18.9
8
0.36
2.88
18.1
9
0.36
3.24
20.4
10
0.29
2.9
18.2
12.5
0.26
3.25
20.4
15
0.19
2.85
17.9
17.5
0.17
2.98
18.7
20
0.19
3.80
23.9
was varied. In practice it will be found that the soil is non-homogeneous. To consider this in a simplified way, the value of resistivity for small values of electrode spacing can be said to represent the soil resistivity near the surface. Also, where the soil resistivity becomes sensibly constant with electrode spacing, this can be said to represent the underlying strata. The formulae
38
36 24
12 , 30 5 28
'6
2.
,
24
22
20
'8
16
' 4
0
4
FIG. 6.131
4
18
18
20
Graph of soil resistivity measurements as a function of electrode spacing 571
Cabling
Chapt er 6
used in Section 11.4 of this chapter assume homogeneous soil conditions and therefore, where they are applied to non-homogeneous soil conditions, it is the 'effective' value of soil resistivity that should be used. The deduction of this effective value is complex, but it must lie between the values deduced for the surface and underlying strata soils. As a practical way of dealing with these difficulties, it is suggested that acceptable results will be obtained by taking the mean value of the measured values down to the maximum depth the proposed electrode will be driven. For example, if it is required to drive an electrode to a depth of 10 metres, using the results given in Table 6.27 the effective resistivity is taken as:
e Q=
36.4 + 20.0 + 17.3 + 17.1 + 15.4 + 17.3 + 18.9 + 18.1 + 20.4 + 18.2
10 19.9 Qm
Where the apparent resistivity starts increasing as the electrode spacing 'a' is increased, the underlying soil strata will be of higher resistivity and there will be less benefit in driving an electrode to this depth. Soil resistivities will vary over a site and it is important to make measurements at each proposed electrode position. Where possible, these measurements should be made before site work commences since any buried earth conductors, cables or pipes can change the pattern of current flowing between the test electrodes, thus reducing the accuracy of the measurements. 11.6.2 Earth electrode resistance measurement
The resistance to earth of an electrode is measured using the same principle as for earth resistivity measurements, i.e., by passing current through the ground and measuring the potential difference across it. In this case the current is made to flow between the electrode under test and an auxiliary earth electrode driven into the ground. This auxiliary electrode may be specially driven for the test or could be any conveniently placed existing electrode. This auxiliary electrode should be placed at a sufficient distance away, such that it does not interfere with the natural distribution of current from the electrode under test. This distance will depend on the size and efficiency of the electrode under test and this will also affect the test method selected. For relatively small electrodes, such as individual pile electrodes recommended for power stations, a proprietary earth resistance measurement instrument can be used as described in (a) below. However, for large low-resistance electrodes such as the combined system on a power station or EHV system, the required distance is so large that a power frequency current injection system as outlined in (b) is necessary: 572
(a) Measurement of resistance by composite instrument Measurements are made using the same instrumen t as that discussed in the previous Section 11.6.1 which is fitted with terminals for current injection and potential measurements, and provides a direct reading of resistance in ohms. A diagram_ matic arrangement of the test is shown in Fig 6.132 where X is the electrode under test, Y is the current electrode and Z the potential probe. To use the instrument in this mode, one of the potential terminals is connected to a current terminal and the electrode under test, the remaining terminals being connected to the potential and auxiliary current electrodes as appropriate. The electrodes themselves are driven in a straight line. With the current electrode Y fixed, resistance measurements should be taken with the potential electrode Z at various distances from X. These measurements should be most frequent at the location where XZ = 0.6 XY since this is where the neutral zone or true resistance should be found. The results should be plotted as shown in Fig 6.133 and the flat portion which forms the neutral zone gives the resistance of the electrode under test. If a neutral zone is not found, the auxiliary electrode should be moved further away at, say, twice the previous distance from the electrode under test, and the test procedure repeated. If the neutral zone cannot be found with a practical distance between the electrode under test and the auxiliary current electrode, then the 61.8% distance rule as described by Tagg [29] should be invoked. This work by Tagg indicates that the true resistance should be indicated at a potential electrode position of 61.8% from the electrode under test to the auxiliary electrode position. Under these circumstances, it is suggested that a family of four graphs is constructed for various current electrode positions and the electrode resistance taken as the mean of the four resistance measurements at the 61.8wo potential electrode distance position. A typical set of results is shown in Fig 6.134. (b) Measurement of impedance by power frequency current injection For a large earth system it may be difficult to estimate its centre to apply the 61.8% rule dis-
CURRENT SOURCE
777A7
N..,
I
I
z
/7A\ <<\\///h ///,
FIG. 6.132 Measurement of earth electrode resistance
V,
Earthing systems
CURRENT ELEC T RODE '1,
POTENT AL PROBE
E-E.7TPC,DE I.NCR "EST
Z'
'CC.
.
1
AZ
'•
I
.T.E NEUTRAL ZONE
26
30
40
30
60
70
30
30
DISTANCE FROM ELECTRODE 3NDER TEST AZ
FIG. 6.133 Graph of electrode earth resistance showing neutral zone
cussed in (a) and to compensate for this the distance to the auxiliary current electrode may become prohibitively long. Furthermore, since the current injection and potential measurement leads are run in parallel (because the electrodes are in a straight li ne), an appreciable error can be produced due to the induction introduced into long measuring leads. Under these circumstances, to improve accuracy, it is preferable to increase the current circulating hrotivil the ground. To provide a sufficient current requires the use of a fairly substantial source, uch as a substation auxiliary supply or a diesel generator set. Where a diesel generator set is used, ilie frequency should be set at say 60 Hz to allow normal frequency (50 Hz) stray currents to be identified, When conducting such tests, the potential measurement leads should be laid at 90 ° to the current injection leads to avoid induction. Further information on current injection techniques is given in Engineering Recommendation
• Each individual electrode should have its resistance to earth measured using a composite instrument in the manner described in the previous Section 11.6.2. It is important that the test links are disconnected to ensure that only the electrode being considered is tested. • Where individual electrode measurements are found to be higher than calculated, or where the calculated rise of earth potential is near the accepted limits, a current injection test should be carried out in the manner described in Section 11.6.2.
,
S34 [31]
.
11.6,3 Commissioning tests fl ,
:ornpletion of the installation of the earthing system , aLter any major modifications, the following tests .) oulci be carried out: if
• Earth cable continuity tests should be completed as detailed in CP1013. 11.6.4 Routine tests
Routine testing consists of the following tests and timescales: • Visual inspections of the station earth network system including earth electrode connections should be carried out at three-yearly intervals. • The earth resistance of individual earth electrodes should be checked using the test methods detailed in Section 11.6.2 of this chapter at six-yearly intervals. 573
Cabling
Chapt er 6
XY
.
SO rn
XY - 116-m
xY = • De ,6
1 I
ELEcTaocE RESISTANCE u
xY = 200 r6 I
,p p71111111w---
050
0150
— ——
0200
=
---------------Fir 03
/
02
NOTE /
20
30
40
50
60
S
50
DISTANCE SYNDICATED ON EACH CURVE IS THE SEPARATION BETWEEN THE ELECTRODE UNDER TEST AND THE CURRENT ELECTRODE
90
IN
Ito
120
130
'SO
100
METRES
DISTANCE OF ROYENTrAL ELECTRODE FROM ELECTRODE UNDER TEST
FIG.
6.134 Graph of electrode earth resistance where the neutral zone is not apparent
12 Lightning protection
12.1 General requirements The function of a lightning protection system is to divert to itself a lightning discharge that might otherwise strike a vulnerable part of the protected structure, and to carry the current safely to earth. The requirements for the protection of structures against lightning are given in British Standard Code of Practice BS6651:
1985. It is necessary to interpret these requirements 574
for power station applications and this is carried out within GDCD Standard 83.
It should be recognised that the requirements of BS6651: 1985 are primarily for the protection of the building structure and special allowances are not made for electrical equipment contained within them. It IS therefore necessary to consider whether additional measures are required to protect electrical equipment, particularly light current devices, from interference or transferred potentials. As a general requirement it is considered essential that the lightning protection system is bonded to the
Lightning protection earth system. This is to reduce the risk of large roNntial differences between the systems, under light..Trike conditions, which could result in flashovers j hence damage to the structure or plant within. ., n ,-, •r. .ill be discussed more fully later, J.
pc
magnitudes and risks Li ghtn in g based on information drawn from . c etion is 198 5 . he UK there are about one million flashes that in ound each decade. Lightning activity varies gr c: the UK and the distribution of lightning flashes er :he We around is given in Fig 6.135. [he important part of the lightning flash, with regard Jamage, is the return stroke. This is that part of in which a charged cell in a thunder-cloud is he Fl as h iarged to earth. The current in the return stroke ranges from about ::( 0) A to about 200 000 A and these follow a log distribution, as follows:
12.2
I 10 lOcr'o 50ro 90q3. 99 07o
of strokes exceed of strokes exceed of strokes exceed of strokes exceed of strokes exceed
A c = LW + 2LH + 2WH + irF1 2 where L, W and H are length, width and height of the
building Another simple case is that of a chimney which is shown in Fig 6.137 and the collection area is calculated as
follows:
A c = TH
2
In practice many buildings have a complex shape, for instance they may be L-shaped or contain a number of different roof heights. Also chimneys or other tall
structures may only give partial cover to lower buildings, for example in Fig 6.137, if H 1 increases significantly it will modify the collection area so that it is no longer a complete circle. Each building therefore has to be treated individually. The probable number of strikes to the structure per year (P) is as follows: P = A, x Ng x 10
200 000 A 80 000 A
6
where A c has units of m 2
28 000 A 8 000 A 3 000 A
li ghtning current rise time is also an important since this is used to calculate the inductive olrages that will occur within the protection system. De majority (approximately 90%) of ground flashes are negative, i.e., the flash current is a negative flow •rom he negatively charged cells in the thunder cloud !ki L:round. For a negative flash, the rise time is less :lan 10 Its this being more onerous than for a positive ,here the rise time is considerably longer. 1s recommended in BS6651: 1985, for the purposes design of lightning protection systems the following ;'.iraineters are considered to be the most severe: {
Having established the value of P, it is now necessary to apply weighting factors to take into account the type and use of the structure under consideration. There are five weighting factors designated A, B, C, D and E by which P has to be multiplied. The overall risk factor (P o ) is therefore given by:
P o =PxAxBxCxDxE
-
I dI ---) ( dt nmx
= 200 kA (max) = 200 kA/As
h,2 probability of a structure being struck by lightning a l ear is the product of the lightning flash density arid :he effective collection area. The lightning flash 1, :nsity (Ng) is the number of flashes to ground per per year. The estimated average annual densities .tr; shown in Fig 6.135. The effective collection area of the structure is the area of the plan extended in all directions to take Jci:ount of its height. For the simple rectangular struc!ure shown in Fig 6.136, the collection area is calculated iN
The weighting factors A, B, C, D and E are presented in Tables 6.28 to 6.32. Having obtained the overall risk factor P o , it is now necessary to use this to assess the requirements for providing a lightning protection system. BS6651: 1985 recommends that for risks less than 10 -5 , lightning protection is not necessary, for risks greater than say 10 -4 , sound reasons would be needed to support a decision not to provide protection. Between these figures, the need for protection must be considered marginal and factors such as consequential effects and the cost of providing a system should be taken into account.
11
follows:
12.3 Application of requirements to power stations This section is intended to give guidance in the application of weighting and risk factors to power stations. The first step in assessing the requirements for individual structures must be to consider the zone of protection afforded by a particular lightning protection system. For structures up to 20 m high it is reasonable 575
Cabling
Chapter 6
FIG. 6.135 Number of lightning flashes to the ground per km 2 per year for the UK
to accept that the zone of protection is the volume contained within a 45 ° cone or wedge as shown in Fig 6.138. This 45 ° cone of protection principle is not considered adequate for structures in excess of 20 m high, since there are many recorded instances of the sides 576
of tall buildings being struck by lightning. This Phe nomenon is best explained by considering the process , that precedes a negative downward flash to ground which is the most common type. The lightning flash starts with a step-by-step descent of a downward leader in random steps and with multiple branching. As this
VP' Lightning protection TABLE 6.28 Use of structure weighting factor A R= , ■
Weighting factor A (use of structure) Value of factor A
Use to which structure is put
The effective collection area for a simple 6 rectangular s[ructure
Houses and other buildings of comparable ;ire.
0.3
Houses and other buildings of comparable s i ze with outside aerial.
0.7
Factories, workshops and laboratories.
1.0
Office blocks, hotels, blocks of flats and other residential buildings other than those included below.
1.2
Places of assembly, e.g., churches, halls, theatres, museums, exhibitions, department stores, post offices, stations, airports and stadium structures. Schools, hospitals, children's and other homes.
1.7
TABLE 6.29 Type of structure weighting factor B
Weighting factor B (type of structure) Value of factor B
Type of construction Steel framed encased with any roof other than metal. H t, 6.137 Collection area for a tall chimney
*
0.2
Reinforced concrete with any roof other than metal.
0.4
Steel framed encased or reinforced concrete with metal roof.
0.8
Brick, plain concrete or masonry with any roof other than metal or thatch.
1.0
Timber framed or clad with any roof other than metal or thatch.
1.4
Brick, plain concrete, masonry, timber framed but with metal roofing.
1.7
Any building with a thatched roof.
2.0
*A structure of exposed metal which is continuous down to ground level is excluded from the table as it requires no lightning protection beyond adequate earthing arrangements.
Hci. 6.138 Zone of protection for structures up to 20 m high
Jurged leader progresses, the electric field between kiIi and earth intensifies until the field at the earth ‘uriace is sufficiently high for an upward streamer '0 be launched to meet the downward leader, and so
complete the path for the return stroke. Upward streamers are launched from the earth's surface at points of greatest electric field intensity, and they can travel in any direction towards the downward leader. Tall structures give a high degree of field enhancement and therefore upward streamers can start preferentially from these. This is particularly true for high current density flashes where higher charges are involved and hence longer upward streamers. However, downward leaders do not have to travel directly downwards, it is therefore possible for them to approach a tall structure in such a manner as to allow a strike part way down, as shown in Fig 6.139. 577
Cabling
Chapter 6 TABLE 6.30
Contents or consequential effect weighting factor C
DOWNWARD LEAD E9
Weighting factor C (contents or consequential effects)
Contents or consequential effects
Value of factor C LENGTH OF LAST LEADER STEP HIGH D,ARGE.
Ordinary domestic or office buildings, Factories and workshops ilot tainable or specially susceptible contents.
0.3
Industrial and agricultural buildings with specially susceptible * contents.
0.8
Power stations, gas installations, telephone exchanges, radio stations.
L.0
Key industrial plants, ancient monuments and historic buildings, museums, art galleries or other buildings with specially valuable contents.
1.3
Schools, hospitals, children's and other homes, places of assembly.
LENGTH OF LAST LEADER STEP 'LOW CHARGE,
ler
N't.,""
\kr
/.7
FIG. 6.139 Lightning strikes on tall structures This means specially valuable plant or materials vulnerable to fire or the results of fire.
TABLE 6.31
Degree of isolation weighting factor Weighting factor D (degree of isolation)
Degree of isolation
Value of factor D
Structure located in a large area of structures or trees of the same or greater height, e.g., in a large town 0.4
Or forest.
Structure located in an area with few other structures or trees of similar height.
1.0
Structure completely isolated or exceeding at least t wice the height of surrounding structures or trees.
2.0
TABLE 6.32
Type of country weighting factor E Weighting factor E (type of country)
Type of country
Flat country at any level
Value of factor E 0.3
Hill country
1.0
Mountain country between 300 m and 900 m
1.3
Mountain country above 900 m
1.7
However, such strikes are likely to be low current density since these have shorter upward streamers. The length of the last leader to complete the strike is called the striking distance. Since the last leader is not confined by direction, all points equidistant from the end 578
of the leader prior to the last jump, can be considered equally likely to receive a lightning strike. Therefore the surface of a sphere having a radius equal to the striking distance can be used to define the zone of protection as shown in Fig 6.140. The practice of using an imaginary sphere in this manner to predict the zone of protection is known as the rolling sphere method, This name is derived from the need, with complex. shaped buildings, to roll the imaginary sphere around and over it to determine the zones of protection. As already stated, the radius of the sphere is equal to the striking distance which is related to the charge and hence current density of the strike. Since the current density varies from one strike to the next a statistical approach has to be used. BS6651; 1985 originally recommended a sphere radius of 20 metres but this is being amended to 60 metres for general use, as this is considered to be much more practical. For buildings with explosives or highly flammable contents, however, the 20 metre radius sphere is still recommended. We must now consider how to apply the method of risk analysis to power station structures. Firstly we must establish an acceptable overall risk factor. As stated above, BS6651: 1985 recommends that for risks less than 10 -5 , lightning protection is not necessary while for risks greater than 10 - i, say 10 -4 , sound reasons would be required for not providing protection. Between these figures the need to fit protection is considered marginal, especially towards the lower figure, and other factors such as consequential effects and economics need to be taken into account. It will . be demonstrated later in this section that the collec tion area of power station main buildings is such that a lightning protection system will be required even If the lower risk value of 10 -5 is used. However, for -5 5 other smaller structures this lower value of 10 . ' considered to be financially unjustified for the nsk
■glIPP"' Lightning protection
6C ,
SC,
25.
PROTEC 7.0'1 agov cED BY L,C,,-17 ■4,;,3 ZONE PROTECMON SYSTEMS OF 9 -1.PLOqNG AND CHIMNEY
FIG. 6.140 Zone of protection defined by rolling sphere method
risiIv d, bearing in mind that any high density current ,!rikes are likely to be to the chimney or main buildings. ;1,:refore, for these smaller structures, the risk is asa probability of 5 x I0 , this being cd -4 :he mid-point between the values of 10 -5 and 10 As far as the weighting factors outlined in the preious Section 12.2 are concerned, a number of these can ! , e treated as standard for all power station buildings. respect to weighting factor A for the use of the , 'ru.Jure for power station buildings, a value of 1.0 is , n , idered appropriate. Weighting factor C for the , . :: uaure contents is set at 1.0 for power stations. The .4 , 1 majority of power stations are sited in flat country therefore a value of 0.3 is selected for weighting or E. Weighting factors B and D, which relate to .re of construction and degree of isolation respectivehave to be considered individually for each structure. 1fal,in2 defined zones of protection and the method ci risk analysis, we can now consider the requirements .or individual structures, starting with the tallest. For tthsil-fired power station the tallest structure will be ihe main chimney and, as already discussed, since this li kely to receive any high current density strikes it • essential that it is fitted with an efficient protection ‘,.•tem. Gas turbine and auxiliary boiler house chimare also of sufficient height that lightning protec•:ofl . s!, sterns must be fitted. Considering main buildings such as turbine halls or 1-0.11er houses, these are too large to be within the zone or protection of the chimney as defined by the rolling 'P here method and therefore it is possible for them .
to be struck by lightning. It is of course possible for 0 main buildings to be within the 45 cone volume of the chimney (as shown in Fig 6.141) and in this case it is possible to claim that the main buildings are less likely to be struck by lightning, particularly by high density strikes, than if the chimney were not there. This degree of protection can be taken into account by selecting a value of 0.4 for weighting factor D from Table 6.31. Main power station buildings are typically steel framed or reinforced concrete with a steel roof, for which a value of 0.8 is appropriate for weighting factor B. Therefore, for main buildings: =AxBxCxDxE = 1 x 0.8 x 1 x 0.4 x 0.3 0.096
Overall weighting factor
From Section 12.2: P = A, x Ng x 10 -6 and P 0 =PxAxBxCxDxE Po A, — 0.096 x Ng x 10 -6 Taking a median value of Ng = 0.5 from Fig 6.135 and a value of 5 x 10 -5 for the maximum acceptable risk, the maximum allowable effective collection areas, as defined in Section 12.1, is: A0 —
5 x 10 —5 0.096 x 0.5 x 10
6
=. 1042 m 3 579
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Chapter 6
N. ZONE - SOME PPOTECT!ON PROVDEG BY OTHER BUILDINGS OR STRUCTURES WITHIN 45 3 CONE OR WEDGE VOLUME
Flo. 6.141 45 0 cone of protection from chimney
This equates to a building size of some 20 m square by 10 m high which is considerably smaller than any main buildings. Even if the risk is increased to 10 -4 thus doubling the collection area, the allowable building size still does not approach that of power station main buildings. Therefore it is required that all main buildings such as turbine halls and boiler houses be fitted with a lightning protection system. Whilst dealing with main buildings it is useful to consider nuclear power stations where there is obviously no main chimney. Such stations tend to be isolated and are taller than the few buildings that may be in the local area. For this degree of isolation, a value of 2 for weighting factor D is considered appropriate. This will have the effect of reducing the collection areas, given above for buildings within the cone of chimneys, by a factor of five. Therefore quite clearly because of their size, the reactor and other main buildings will need to have a lightning protection system fitted. We now need to consider the remaining smaller structures that will be present on a power station site. The requirement for lightning protection will be dependent on the degree of protection afforded by taller structures and it is convenient to use three classes according to location:
(b) Structures which are within the 45 ° cone or wedge volume of chimneys or main buildings, but not covered by (a) need to be assessed with respect to their collection area. As before, constants A, C and E are fixed and, since in this case a consider. able degree of protection will be given by the taller structures, a value of 0.4 is chosen for weighting factor D. As previously discussed, the maximum allowable overall risk factor P o is taken as 5 x 10 -5 .
(a) Structures that are within the zone of protection of chimneys or main buildings as defined by the rolling sphere method are not required to be fitted with a lightning protection. system.
(c) Structures which are outside any zone of protection are again assessed on their collection area. As be fore, constants A, C and E are fixed. In this case a value of 1 for weighting factor D is considered
580
Now the overall risk = A x BxCxDxE factor = IxBx 1 x 0.4 x 0.3 = 0.12B Maximum allowable collection area A, A,
5 x i0 Ng x 10 -6
X
0.12 x B
416 Ng x B
For any particular power station, Ng is selected according to its location from Fig 6.135. Weighting factor B is selected according to type of structure from Table 6.29.
Lightning protection appropriate since there will be a number of structures of similar height and taller in the area.
additional connection is required. The continuity of this connection should however be checked and not merely assumed.
\ow the overall risk = AxBxCxDxE = IxBx 1 x 1 x 0.3 = 0.3B
factor
\laximurn allowable .: ollection area A,
Ng x 10
- 6
x 0.3 x B
166 Ac
Ng x B
For any particular power station, Ng is selected according to its location from Fig 6.135. Weighting factor B is selected according to type of structure from Table 6.29. In summary, lightning protection systems shall be fitted ,tructures as follows: • \fain, gas turbine and auxiliary boiler chimneys. • \lain buildings including boiler, turbine and reactor buildings, irrespective of height. 0
• Buildings or structures that are within the 45 cone or wedge zone of chimneys or main buildings but outside the protection zone as defined by the rolling sphere method, that have a collection area in excess of A, = 4I6/(Ng x B).
12.4.1 Main and gas turbine chimneys
It is now standard practice to construct single and multi-flue chimneys from reinforced concrete, therefore the lightning protection system details herein are appropriate to that type of construction. The air termination is formed using the metallic cappings (or metallic flues if provided), ensuring that capping segments are adequately bonded together to be electrically continuous. Where metallic cappings are not provided, a metal strip coronal band must be fitted to each flue. The connection from the air termination on each flue is brought down to a test clamp as shown in Fig 6.142. In addition, the concrete windshields of multi-flue chimneys are also provided with a strip coronal band which is bonded direct to the windshield reinforcement. This windshield corona] band can be omitted if handrails are fitted since these can form the air termination, but in this case handrail sections must be bonded together and direct to the windshield reinforcement rods. Finally an external bond should be provided between reinforcement of flue and windshield where reinforcement is not continuous, as shown in Fig 6.142. Coronal bands and all connections
CORONAL BAND BONDED TO DOWN CONDUCTOR
° • Buildings or structures which are outside the 45 cone or wedge zone of chimneys or main buildings that have a collection area greater than A, = 166/(Ng x B).
DOWN CONDUCTOR
• All structures containing explosive or flammable materials shall be protected in accordance with BS6651: 1985.
DOWN CONDUCTOR FIOLDFASTS
REINFORC EM EN T
12.4 Protection system design I flL section is intended to give the principles of system Ln and therefore constructional details of mdidual components are not included. Reference should 'e made to GDCD Standard 83 for constructional of components. li ghtning protection scheme has three essential :1;:ments which are the air termination, the downconJuctors and the earth termination. The power station tri mures are discussed in the following sections with 7t.Lsrteet to these elements. As a general requirement, the combined resistance earth of each lightning protection system should UI e\ceed 10 ohms. In addition, each individual lightrmg protection system must be connected to the main ‘:allort earth network to reduce the risk of dangerous N'cntials occurring between earth systems. In cases here a connection exists via structural steelwork no
TEST CLAMP
1
HANDRAIL BONDED TO REINFORCEMENT
,
D4TERNAL BOND BE T WEEN REINFORCEMENT OF FltA AND WINDSHIELD WHERE REINFORCEMENT IS NOT CONTINUOUS
Flo. 6.142 Typical arrangement of air terminations and down conductors for multi-flue chimneys 681
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within 12 m of the flue top are to be formed using copper strip which has been seamless lead covered to protect it from the flue gases. The reinforcement of the windshield should be utilised as the clowneonductor subject to the following conditions: • "Ole reinforcement should be secured by tie wires at all laps and intersections, the laps being bonded by at least two tie wires. • External connections should only be made to reinforcement that is part of a continuous mesh. All metalwork including aircraft warning light access doors and handrails shall be bonded to the reinforcement. Bonding of small isolated metalwork such as steeplejack access fittings is not necessary. At intervals of approximately 45 m throughout the height of the chimney, all continuous vertical runs of metal including stairways, lift structures, cable armouring and reinforcement of windshield and flues should be bonded together. It is normally convenient to carry out such bonding at the levels at which aircraft warning lights are fitted. The downconductor system shall be brought out near ground level to a total of four test clamps spaced equally around the perimeter of the chimney. To ensure adequate current carrying capability, each test clamp should be bonded directly to a minimum of four reinforcement rods. In addition, where flues extend to the chimney base, the windshield and flue reinforcement should be bonded through to the base reinforcement. An earth termination formed from earth rods should be provided adjacent to each test clamp position. Copper strip is used to connect the earth termination to the test clamp. 12.4.2 Main buildings Where roofs are constructed from metal decking, complying with the minimum thicknesses given in Table 6.33, the roofing may be regarded as the air termination and externally applied tapes are not considered necessary. This applies even if the decking is covered in insulation, such as bitumen felt, since these materials offer negligible resistance to lightning. When metal decking TABLE 6.33 Roof thickness Material
582
Minimum thickness, mm
Gals anised ocel
0.5
Stainless steel
0.4
Copper
0.3
Aluminium and zinc
0.7
l ead
2.0
is used as the air termination it is important to ensure that there is adequate electrical continuity betwee n sheets, and between sheets and the steel framework, Where roofing is formed from non-conducting m a terials, e.g., in-situ or precast reinforced concrete, air terminations in the form of metal strip mu st b e provided around the perimeter and over the roof to form a mesh not exceeding 10 m x 20 m. Any PrOjecdons above the general roof level, e.g., parapet wails, vent pipes, heating and ventilating exhausts, should be bonded to the roof steelwork or the air termination network. If such projections are non-conducting, th ey need to be provided with metal strip air termination s bonded to the roof termination. Where possible, steel or reinforced concrete column s should be utilised as downconductors. Columns fo r use as downconductors need to be nominated early in the civil programme to enable provisions to be made for the connection of air and earth terminations. The nominated columns should be spaced at intervals not exceeding 10 m around the perimeter of the building. For steel columns a welded boss should be provided for bonding connections. With reinforced concrete columns for bonding connections, a tag should be provided which is welded or clamped to at least four reinforcement bars to allow adequate current distribution. Sufficient bonding connections should be provided between metal decking or air termination networks at each column nominated as a down conductor. At each concrete column used as a downconductor, the reinforcement should be tied to the floor reinforce. ment to form an earth electrode. In addition, the tag connection to the reinforcement at the bottom of the column should be bonded to the station earth network. Where steel columns arc used as downconductors, a tag should be provided at the column base which is connected either to the supporting pile (if present) or to at least four reinforcement bars in the base concrete. This tag is to be bonded to the boss at the base of the steel column and to the station earth network.
12.4.3 Other buildings All other buildings which are deemed to require lightning protection, when assessed in accordance with Section 12.3 of this chapter, should be protected in the following manner. Air terminations should be formed using the same techniques as described for main buildings in the previous Section 12.4.2. Again where possible, as with main buildings, structural steel or reinforced concrete columns should be utilised as downconductors. Facilities should be Pro vided to allow a connection to be made from the base of the column to an external earth electrode. This can be achieved by providing a lug or boss on the outside of the column, if exposed, or by the provision ()fa duct from the column base to an external earth Pit.
Lightning protection here it is not possible to utilise the fabric of the ‘1,wnconductors, then separate metal strip o building as dhave onductors to be provided down the outside of building. The spacing of downconductors around [ he should not exceed 20 m for buildings up building '0 m high. For buildings over 20 m high, downto be provided at intervals not ex..onJuctors need around its perimeter. ding 10 m An earth termination consisting of copper-clad steel rh rods complying with ESI Standard 43-94 should at the base of each downconductor. The io e provided onnection to earth is completed using copper strip ua a test link. These test links should be located in a po,ition with suitable access for testing. 12.4.4 Buildings requiring special considerations
\‘, ben designing a lightning protection system it must
recognised that lightning currents will seek out the l o‘k est im pedance and hence the most direct path to earth. It should be the design intent to provide low [-npedance paths around the perimeter of buildings, thus reducing the magnitude of currents flowing through the building which might result in interference or ,ideflashing. For simple rectangular buildings, such as [hat shown in Fig 6.143, this can be achieved by nominating columns around the perimeter of the building for special treatment as downconductors or by using separate external downconductors. Where there are annexes attached to the building these can be readily incorporated by running tapes over the roofs. However, for complex buildings such as that shown in Fig 6.144, special provisions are necessary if it is required to prevent substantial currents flowing through the building where sensitive equipment may be housed. In Fig 6.144 the building length is such as to demand a number of downconductors along its length. In this case it is not considered permissible to run conductors down from the highest roof, across the lowest roof an d back up to the other roof to connect to the downhe
FIG. 6.144 Protection scheme for a complex building design
conductors along the perimeter of the building. If downconductors were installed in this manner the lightning current from a strike at location A (Fig 6.144) would be unlikely to follow such a tortuous route and would seek a more direct route through the building structure, by sideflashing where necessary. The solution to this type of problem is to provide catenaries across the void to interconnect the air terminations on the two roofs. This provides a low impedance path to the peripheral downconductors and achieves a higher degree of current sharing between them. 12.4.5 Fuel oil storage tanks
This section relates to heavy oil and gas turbine fuel oil tanks. In these cases the tank structure itself forms the air termination and the downconductors. To facilitate connection to the earth termination, bosses should be provided near the base of the tank at intervals not exceeding 35 m around the perimeter of each tank. An earth termination formed from earth rods complying with ESI Standard 43-94 is provided at each boss location. The earth termination is connected to the boss, via a test link, using copper strip. 12.4.6 Flammable gas production and storage plant
Hydrogen generation plant
FIG. 6.143 Protection system for a simple rectangular building
In order to provide adequate protection against lightning, the complete hydrogen plant and storage area should be covered by a suspended horizontal air termination network. This applies even when the plant is in the protective zone of the chimney or main buildings. The network shall enclose all the buildings and storage areas of the plant and should be con583
IP" Cabling
Chapt er 6
structed in accordance with the requirements of British Standard Code of Practice BS6651: 1985, Clause 21. The. number of horizontal conductors is determined from the plant layout using a protective angle of up 0 to 45 ° between conductors and a maximum of 30 outside the outer conductors, as shown in Fig 6.145. The height of the horizontal conductors needs to be sufficient to avoid any risk of flashover to the protected structure and due account must be taken of items such as vents that may be higher than the main structures. The minimum clearance of these conductors and their supports from the structure should be 2 m. An earth electrode should be provided at the base of each conductor support and these are interconnected by a ring conductor. This ring conductor should preferably be buried to a depth of 0.6 m, but may be run above ground where this is more convenient for bonding other objects or for testing. All major metal forming parts of the protected structure, including continuous metal reinforcement, should be bonded together and connected to the lightning protection system. To achieve this, at least two connections should be made to the ring conductor and, if possible, connections should be equally spaced around the perimeter of the structure at intervals not exceeding 10 m. In addition, the ring conductor should be connected to the station earth system.
The materials and bonding should be in accordanc e with BS 6651: 1985, Clause 21, and particular atten.. lion is drawn to clauses 21.2.6 and 21.2.7 which detail bonding of pipes, cables, etc., entering the area, I n _ sulated flange points of the type shown in Fig 6.146 are to be fitted to the delivery main immediately out s id e the compound fence. Propane storage cylinders The propane cylinder storage compound is to be treated in a similar manner to the hydrogen generation pla nt.
12.5 Assessment of risks of sideflashing and interference When a lightning protection system is struck by lightning, large potential differences are produced across it. The overall potential produced has two components. The first is the product of the current and the resistance to earth; the second is the product of the rate of change of current and the inductance of the downconductor system. Whilst there will be a phase difference between these components the worst case, which is given by the simple addition of the two products, is normally used in any assessment. To illustrate this point, consider a building 20 m high fitted with an air termination and a single downconductor. In Section 12.2 of this chapter we defined the maximum design current as 200 kA and, in Section 12.4, we require a maximum earth termination resistance
GABLE EARTH RING AT EASE OF MASTS S,SPE'40ED A1A TERMINATION M 1 C SOLT AND NUT
5.15 VENDED AIR TERMINATION To STATION EARTH NETWORK ZONES OF PROTECT ON AT MAST ZONES OF PROTECTION AT MAximum SAG OF SERIAL CONDUCTOR
INSULA TING SLEEVE
OS WASHER
MINIMUM INSULATION RESISTANCE 2M ci AT 500 JOLTS
Flu. 6.145 Typical catenary air termination system for flammable gas production and storage plant
584
FIG. 6.146 Insulated flange point for a gas pipeline
Lightning protection Therefore the potential difference across earth termination is:
or IC) om
the
.
W+t
IR = 200 x 10 3 x 10 = 2 MV
VR
lienee the base of the downconductor will be raised / \IV above remote earth, nsider the second component which is the co rotential difference across the clownconductor. A downonductor tape has a self-inductance of the order of and front Section 12.2 we take the maximum rate of change of current to be 200 kA/As (2 x ). Therefore the potential difference across s lo m the height of the building is:
di x f XL VL = (— dt ) max e
i% here
For strip conductors, effective radius has to be used and this can be calculated using the formula:
3.5 where W = strip width, m t
Having calculated the transfer inductance NIT, the inductive voltage VL generated in the loop shown in Fig 6.147 is given by the equation: di V L = (— dt )
x 20 x 1.5 x 10
-6
= 6 IVIV Therefore, the total rise of potential of the air termination above remote earth is: V = Viz
(kV)
n = number of downconductors that simultaneously share the lightning current
Ls = self-inductance 11
X max
Where 1' = loop length, m
downconductor length, m
VL = 2 x 10
= strip thickness, m
VL = 2 + 6 = 8 MV
This simple example is pessimistic since the most onerous lightning parameters and earth electrode reistance have been used. Also, a single downconductor has been considered where in practice on a tall building :here would be many, which would reduce the induclance between the air and earth terminations considerably. Nevertheless it does demonstrate the order of magnitude of potential gradients that can occur in sructures when subjected to a lightning strike. These %oltages do not constitute a danger to the structure ;! , elf, but they can have an effect on equipment such as pipes or cables in the vicinity of the downconductors. From this point of view it is necessary to determine .nductively-generated voltages to assess the risk of side:lashes between equipment and downconductors. For the calculation of voltages between a lightning onductor and other metalwork we cannot use selfdiductance as in the previous example. In this case e need to use the transfer inductance, which is the , oupling generated by the self-inductance minus the mutual inductance to the metalwork. From BS6651: 19 8) the transfer inductance MT may be calculated Irorn the formula:
Now taking the example shown in Fig 6.148, we have an earth cable bonding a cubicle down to the main station earth network. The earth cable is run parallel with a downconductor at a distance of 4 m for a length of 20 m. For a 25 mm x 3 mm strip conductor: r e = (0.025 + 0.003)/3.5 = 0.008 Now MT --- 0.46 log 10 (4/0.0008) = L24 pi H/rri For a design value of rate of change of current of 200 kA/its (2 x 10" A/s): VL = 2 x 10 11 x 20 x 1.24 x 10
DOWN
-6
= 5 x 10 6 V
coNouctoa
,
MI = 0.47 logio —
%% here S
ti1-1/m BOND
distance between downconductor and other metalwork, m
r = radius of downconductor, m
METAL PIPE CONDUIT iRu , :xiNG OP 07.EP METALWORK
FIG. 6.147 Transfer inductance of a simple loop
585
Cabling
Chapt er 6
e MT
di And VL
dt
44,
max
= 200 x 10 11 x 20 x 0.41 x 10
-6
VL = 1.64 x 10 6 V Again taking the dielectric strength of air as 500 kV/ the flashover distance is: 1.64 x 106
D—
rn,
— 3.28 m
500 x 10 3 EARTH ZA.BLE
CONCLC TOR
VAT.CN EARTH RING
Fic. 6.148 Inductive voltage generated in a toop
Taking the dielectric strength of air to be 500 kV/m it is clear that sideflashing could occur between the cubicle and the downconductor. Now it is interesting to compare the difference when a reinforced column is used as the downconcluctor instead of metal strip. Consider a concrete column 1 m square with reinforcement to within 0.05 m of the surface, so that all reinforcement is contained in a square having 0.9 m sides. A reasonable approximation of the inductance for such a group of reinforcement may be obtained by treating it as a box-section of the same dimensions. To calculate the inductance it is first necessary to calculate the effective radius thus: W+t
MT =
0,9 + 0,9
IC —
—
3.5
The air space between the column and the panel is the spacing, less half the column width which is 3.5 m, therefore sideflashing should not occur. This demon. strates one of the many advantages in using the building structure as a downconductor since the larger size of the column has had the effect of reducing the inductively-generated voltage by a factor of 3 compared with that obtained using a metal strip down_ conductor. Al! the examples so far have only considered a single downconductor, whereas in practice any large building will have a number of downconductors which will share the current to some degree. The formula for induced voltage (VT) has a factor n which represents the number of downconductors. The basic formula therefore assumes that the value of di/di is equally shared by the downconductors. However, BS6651: 1985 recognises that in rectangular or square buildings with more than four downconductors, the corner down. conductors take a disproportionately large share of the total current. It is therefore recommended that a factor of 30% be added to the inductive voltage generated by corner downconductors. Conversely, in the central area of structures having many downconductors, the value of di/dt is lower by approximately 30%. As an example, consider a building which utilises twelve reinforced concrete columns (having the same dimensions as the previous example) as downconductors. Now for metalwork bonded at the bottom to the downconductor and run parallel for 20 m at a distance of 2 m: 0 46
.
0.51
0.51 m
3.5
Using the same physical arrangement and lightning parameters as in the previous example we have: MT = 0.46 login (S/r)
and di VL
= (;)max
586
em -r 71—
= 2 x 10 11 x
20 x 0.27 x 10 -6 12
= 0.46 login (4/0.51) = 0.41 gli/m
2
log IP ( —) = 0.27 gH/m
VL = 90 kV
Lightning protection uctor add 30%, therefore V
L
corner CO tot a d for a central conductor subtract 30%,
=
LV an
Tk rig
63 kV. strength of air as 500 kV/m, w dieiecuic !t
not occur unless the panel is withcorner downconductor or within , :14 min of a a central downconductor. In fact the dio t' ,irenfth of concrete is si milar to air, so these can be assumed to apply to air, concrete inirture of [hese mediums. method of calculating inductive voltages, by H, all central or all corner downconductors carry urrent, is not considered rigorous when applied ,. • 'Ar:le steel or reinforced concrete framed buildings. the downconductors are connected I L i: . is because orizontal conductors which themselves have im_ 'I and therefore the downconductors nearest the carry a higher proportion of current. ,•r:ke point will building structure itself is used as a downnerc the n,Meior, there will be a number of vertical paths .,rmei.1 by the columns interconnected at each floor c cI as a result of the horizontal paths formed by Figure 6.149 shows the most significant current r, a steel or reinforced concrete framed building j ,irike on one corner. As can be seen, the current •!: ■ :Jcs at each building node so that better current ring is achieved at lower building levels. It should .: ) be noted that currents are generally greater in ; m[plieral than in interior conductors. [ he method given in I3S5651 for dealing with mul. dov,nconductors is regarded as adequate for ..,:neral use. However, for special cases, such as when equipment is located at high level in a builda more rigorous calculation should be carried
Having explored the methods of calculating inductively-generated voltages and typical values, it is now necessary to consider what precautions are necessary against the risk of sideflashing. In general there are two solutions, either to ensure there is sufficient distance between plant and downconductors to prevent sideflashing or to bond the plant to the downconductor. In practice, power station buildings tend to be large in size and as a consequence they require many downconductors. The calculated inductive voltages are therefore relatively small as demonstrated in the last calculated example for a building with twelve downconductors. In that example, the clearances required to prevent sideflashing were less than 250 mm for a corner downconductor and less than 150 mm for a central downconductor. This indicates that as a general policy, bonding of plant to downconductors should not be necessary if the following rules are observed: • Bond reinforcement or steelwork across expansion joints and the like at all floor levels to achieve optimum current sharing. • Where practical, sensitive electronic equipment should be located at low level in the building. • No equipment should be mounted on or very close to outside columns or steel reinforced walls. Quite clearly it is not practical to calculate sideflash distances for all the vast amount of plant within a power station, and it is suggested that if the above rules are followed this is not necessary other than in special cases. An example of a special case is nuclear safety equipment.
N:1
12.6 Inspection, testing and records
F1
6. paths in [49 Distribution of most significant current a steel or reinforced concrete framed building (..
A log book should be employed to record the results of all visual inspections and resistance measurements. All lightning protection systems should be visually inspected during installation and after completion to check compliance with BS6651: 1985. All accessible components of the system should be visually inspected at intervals not exceeding 12 months. Upon completion of the installation, each lightning protection earth electrode should have its resistance measured to demonstrate that it does not exceed 10 as required by 8S6651: 1985. The method of testing should be as given in CP1013: 1965. Tests to measure earth resistance need to be repeated at regular intervals. Because the lightning protection system is bonded to the station earth network which is a high integrity system, it is not considered necessary to carry out these tests at 12 month intervals as suggested in BS665I: 1985. It is therefore recommended that lightning protection earth electrodes be tested at the same frequency as the station earth electrodes which is every 6 years. 687
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13 Lighting, heating and small power systems
• General planning To resolve the type of lighting system which will achieve the desired objectives. Planning of the final sche me using accurate data to ensure the most economi ca l and efficient final design.
• Detailed planning
13.1
Introduction
Lighting is both an art and a science. It can be both decorative and functional although the balance between decoration and Iiiih:tion will vary with application. The applications considered in a power station are essentially functional. The function of the lighting system in a power station is to provide adequate illumination for safe plant operation and personnel movement. The li ghting system should also contribute to achieving an acceptable overall environment of the work area. One of the most fundamental decisions to be made when designing the lighting of any interior is the relationship between daylight and artificial (electric) light. This can take three forms: • Rely on daylight during the daytime and design electric lighting only for night-time conditions. • Use daylight as available but supplement it as required by electric lighting. • To ignore daylight and operate by using electric lighting only. Artificial light is necessary in a power station for two main reasons. The first, quite simply, is that the operation of a power station is a continuous 24-hour per day process and the after dark activities must be catered for; the second reason is that the architecture of the plant and buildings of a power station make it uneconomic and invariably impossible to illuminate adequately with natural daylight.
13.2 Lighting system design Lighting design is a complex process and no hard and fast rules can be devised which will suit all applications or every designer. The Chartered Institute of Building Services (GIBS) Code for Interior Lighting (1984) offers a design approach that represents reasonable practice and is used by the CEGB as a guide to plan and calculate the lighting requirements for power stations. The recommendations given in this code, and previous issues, reflect and are written confirmation of the good design practice that has been adopted by the CEGB for a considerable number of years in the design of power station lighting systems. The overall design process proposed by the CIBS code consists of five stages: Determine the objectives of the design in terms of the safety requirements, task requirements and the appearance required.
• Objectives
Specify the design objectives as a set of compatible design criteria, acknowledging those objectives which cannot be quantified.
• Specification
588
• Appraisal The installation is reviewed after corn. pletion in order to assess its success in terms of the design objectives and its acceptability to the us ers (in the case of the CEGB, the power station operating staff). The following sections consider the application of the above design process to the design of power station main AC lighting systems. The procedure is equally valid for the design of emergency lighting systems, which are discussed in Section 13.3 of this chapter.
13.2.1 Objectives The design of the lighting system for a power station must meet the specified standard service illuminance and the essential requirement of high reliability, whilst si multaneously satisfying economic requirements m terms of low capital, energy and maintenance costs over the design life of the installation. Due regaid must also be paid to the desirability of minimising the number of different light sources stored as spares by the power station. Some, if not all, of the above objectives are common to all installations whether in power stations, industrial or commercial premises. One area unique to power stations is the design life of the installation. All installations in power stations are designed for a minimum life of 25 years. The tendency now with modern nuclear stations (e.g., Sizewell B (PWR) power station) is to design for an extended life of 40 years. The lighting equipment manufacturers must present data in support of their claims for the life of their equipment. This must be borne in mind when considering, in addition to the energy and maintenance costs, the ease of replacement and refurbishment of equipment over the design life of the station. An additional requirement placed on the lighting installations of modern nuclear power stations is the support of the safety-related equipment which has nuclear safety duties. Although the lighting installation is not directly safety-related it is designed to aid the satisfactory supervision of this essential safety-related equipment. Particular attention is therefore given to the main and emergency operation lighting systems in areas of the station containing such equipment, or equipment required to be operated following a trip of the nuclear reactor. It is also important when considering objectives to establish the design constraints. There are many con straints which affect the design objectives, such as en vironmental considerations (which may limit the range of acceptable luminaires) and the physical problems of access.
Lighting, heating and small power systems 13.2,2 Specification defined the objectives for the main AC ininti.r be expressed in the form of a these , ,; ILc io n, :Tecification giving, wherever possible, meawig., the standard service illumimt i t e s en in CLGB, GDCD Standard 31). Where annot be expressed as measurable quanti.., ihe lighting designer must exercise experience and .,!:cinent to replace calculation. It is important that „hiceti%es which cannot be quantified are not over-
13 2.3 General planning Mien the design specification has been established, purpose of the remaining stages of design is to -.instate these physical requirements into the best pos1e solutions. There are no hard and fast rules about .11 , to plan a lighting installation. Experience and ement will usually dominate the planning process. i.,: he planning stages can be divided into general and iled planning. the first stage in the general planning of a lighting .r-da/lation is to consider the interior to be lit, its rroportions, its contents, and most importantly the ::• re of lighting to be adopted. lectric lighting systems fall into three basic • General lighting. • I ocalised lighting. • local lighting. I i:htin ,7 systems which provide an approximately ii niform distribution of light over the entire working :'line are called general lighting systems. The lumiare normally arranged in a regular layout. The ii rrearance of this type of installation is usually tidy Hi may be regarded as being rather bland. General :;.21iti lig. is si mple to plan and requires no co-ordination task locations. The greatest advantage of such —reins is that they permit complete flexibility of task io,ation. For this reason, general lighting systems are iiredorninantly used for lighting the major plant areas rower stations. The disadvantages of bland appearand increased energy requirement to illuminate he \Ode area to the same illumination level are Lii%%eighed by the functional requirement for a flexible ii ;hting system throughout the life of the power station. •Localised lighting systems employ an arrangement it luminaires designed to provide the required service wurninance on the work areas together with a lower Illuminance for the other areas provided by 'light spill'. IThe layout of localised lighting must be co-ordinated %s al) the equipment and task positions. The system can be inflexible and it is essential that correct information fl .equipment and task locations is available at the design stage. The magnitude and complexity of the .11
design process for a power station means that this information is often not available at the required ti me. The inflexibility of this system of lighting, where changes to the equipment layout can seriously impair the efficiency of the lighting, make it unsuitable for use in the major plant areas of power stations but it is employed in certain other areas. Power station control rooms over the last decade, for example, have utilised contoured lighting schemes to illuminate the control surfaces of the control desks and the fronts of control panels, allowing 'light spill' to illuminate other areas of the control room floor for access purposes. Local lighting provides illumination only over the small area occupied by the task and its immediate surroundings. It is normally associated with a general lighting system which provides sufficient ambient illumination for staff movement and the performance of other minor and incidental tasks in the area. This lighting system is also employed in power stations for workshops, crane lighting and other areas where high illuminances are necessary for the task to be undertaken. Local lighting is frequently provided by luminaires mounted on the work station. An example is the crane lighting which, by means of tungsten halogen lamps in flood lantern luminaires mounted on the crane, provides instantaneous lighting of the working surface. The designer will consider all three lighting systems (general, localised and local) when planning the lighting of a power station, and will to some extent utilise all three systems to provide the most efficient lighting arrangement for the diversity of tasks and buildings. One objective that must be considered at the general planning stage is the desirability of minimising the number of different light sources that need to be stored. The choice of lamp will affect the range of luminaires available and vice-versa. There is a considerable variety of lamps available to the designer, from tungsten to gas discharge lamps (including the very versatile and efficient tubular fluorescent). The requirements for lamps are specified in GDCD Standard 32. The advantages and disadvantages of lamps used for lighting power station interiors are summarised in Appendix J. When selecting a range of suitable lamps, the designer must consider the types of luminaires which are available and the degree of light control and light output required. In the choice of luminaire the designer can exercise a combination of professional judgement, personal preference and economic analysis. Luminaires in a power station have to withstand a variety of physical conditions, such as vibration, moisture, dust, ambient temperature, general ill-treatment (including theft), etc. The onus is on the designer to specify safe equipment. CEGB Standards have been produced to assist the designer in specifying the required standard of equipment. These are GDCD Standards 35, 36 and 37. 589
Cabling
Chapter 6
Specialised luminaires are also required for power stations to warn aircraft or shipping, or to light hostile and hazardous environments. These luminaires are discussed in Section 13.4 of this chapter. Luminaires may be classified in a number of ways, the most important being on the basis of their light distribution since this influences the distribution of illuminance and the directional effects that will be achieved. The luminous intensity distribution (or light distribution) from a source is usually shown graphically in a polar curve, see Fig 6.150. The curve is produced by plotting the luminous intensity in a series of directions within one vertical plane through the source, and defines the way in which the luminaire controls the light from the lamp. The first way to classify the luminaire from its light distribution is in terms of the proportion of the total light output of the luminaire in the upper and lower hemispheres of the polar curve. A luminaire giving all or very nearly all of its light downwards is called direct, and one giving all light upwards indirect. Between these two extremes the intermediate types are called semidirect and semi-indirect. The fractions of upwards and downwards light expressed as percentages of the total light from the luminaire are termed the flux fractions. The flux fraction ratio may also be quoted, although this may be calculated from the flux fractions, i.e., Flux fraction ratio
Upper flux fraction Lower flux fraction
The ratio of the luminous flux from the luminaire to that from the lamp is called the light output ratio (LOR). Light output ratio, LOR —
Light from luminaire Light from lamp
The light from the luminaire is the sum of the upwards and downwards light from the luminaire. It is also possible to express the light output ratio in terms of its upwards and downwards components:
Flu. 6.150 Example of polar curve
classification. This is a procedure whereby the curve of direct ratio (the proportion of downward light from the fitting that is directly incident on the working plane) against room index for an actual luminaire is compared with a family of ten hypothetical curves which cover the whole range of possible downward concentrations, ranging from the most concentrated to the most widely dispersed (see Fig 6.151). The room index is a measure of the proportions of the room; the area, perimeter and height of the fittings. The area between the curves is termed a zone. From the hypothetical curves a family of ten standard zones results, identified by the numbers 1 to 10. The curve of the actual luminaire will lie within one of these zones and the luminaire will then be classified and assigned a BZ number, e.g., BZ5 means . the curve lies within zone number 5. Manufacturers of luminaires will provide the following information on their luminaires: • British Zonal (BZ) classification. • Upward light output ratio.
Upward light output ratio, ULOR Upward light from luminaire Light from lamp
Downwa.rd light output ratio, DLOR Downward light from luminaire Light from lamp
The light output ratios and flux fractions are important to the designer because they are involved in assessing the level of glare associated with a luminaire. The second way of classifying luminaires according to their light distribution is the British Zonal (BZ) 590
• Downward light output ratio. • Luminous area. The luminous area is the area of the luminous part of the luminaire as seen from vertically beneath it. The manufacturers may also quote the upper and lower flux fractions or flux fraction ratio, though these may be calculated from the output ratios. These characteristics of the luminaire enable the designer CO determine at the general planning stage the glare indices, the acceptable luminaires and surface reflectances, and the utilisation factor. Glare occurs whenever one part of an interior is much brighter than the general brightness in the interior-
Lighting, heating and small power systems
BZ 2 3
affect it, the brightness of the source (BO, the brightness of the background (Bb), the apparent size of the source (a solid angle co) and the position of the source in relation to the direction in which the eyes are looking (represented by an index, p). The relationship between the direct glare index and these factors is: Glare index =
10 logio[ 0.5 x constant 8
10
06
5 08 125
2
2.5
3
ROOM INDEX
1 rt, 6.151 Graph of direct ratio against room index
:!,ffe
can have two effects; it can impair vision, in case it is called disability glare and it can cause .!: , ,orn fort in carrying out the visual task, this is called !,,dinfori glare.
An important distinction is that
H'...:.seen direct glare caused by the primary sources, 're lamps and luminaries, and indirect glare due to - ...,ondary sources, surfaces which are too bright or reflections of the primary source from the glossy Indirect thare usually depends on elements in the
rr: crrior, wall
and ceiling finishes, equipment surfaces
ihe general decoration, which are normally outside r.rle control of the lighting designer. \ practical system adopted by the CEGB for the p. unterical evaluation of direct glare is the IES glare
rl dex . system. This system for artificial lighting ina procedure for the evaluation of discomfort based on the four factors which most
,r4lla1ions sets out „dare
E
B s"
w
)0.8 X
Bb
1.6 P
The implementation of the IES glare index system is fully discussed in specialist design manuals such as the Electricity Council's Interior Lighting Design Manual and the CIBS Code for Interior Lighting. The utilisation factor (UF) for a luminaire is a measure of the efficiency with which light from the lamp is used for illuminating the working plane, i.e.,
the luminous flux which reaches the working plane expressed as a ratio of the luminous flux emitted by the lamp. Although utilisation factors can be calculated by the designer (refer to CIBS Technical Memorandum No 5), most manufacturers publish UFs for standard conditions for their luminaires. It should be noted that a range of UFs are normally quoted for each luminaire type. The range of factors is dependent on the efficiency, distribution and spacing of the luminaires, as well as the room proportions and reflectances of the room surfaces. From the UFs, luminaires can be ranked in order of the installed efficacy they provide so that the most efficient luminaire, capable of meeting the other requirements, may be selected. However, the designer must remember that the luminaire with the highest installed efficacy may not offer the highest operating efficacy. An aspect that should be considered at the general planning stage is the maintenance of the installation. Lighting systems must be serviced regularly and this must be allowed for at the design stage. The ease with which luminaires can be installed and maintained will affect the overall economics and convenience of the scheme. The most powerful constraints on any design are financial. The designer must consider the installation and operating costs and be satisfied that the proposed scheme is a sound economic proposition. Scheme economics are difficult to judge in absolute terms and for this reason comparisons are normally used. The cost of owning and operating an installation is conveniently divided into 'capital' and 'operating' costs as follows: • Capital costs: lamps, luminaires and associated equipment, installation and cabling. di Operating costs: energy costs, lamp replacement costs (including labour) and maintenance costs. 591
Cabling
Chapt er 6 •••••••...
The capital cost and operating cost must be scrutinised and controlled at all stages of the design process. It is common practice in the design of power station lighting schemes to carry out a simple economic comparison, at the general planning stage, to assess the most economical selection of lamps and luminaires. To make this comparison, the fittings are assumed to illuminate a large unobstructed area. In calculating the overall cost per lumen of ‘,arious light fittings certain other assumptions are made: • Calculations of lamp costs are not based on the 'rated average life' of the lamps as given by the lamp manufacturers, but on the time taken for 203/4 of the installed lamps to fail, or the time taken for lumen output to fall to 70Wo of the initial output, whichever is the shorter. This corresponds to the usual maintenance programme. • Longer life figures result from the above assumption but the output figures used in the lighting design are lowered. For the purposes of the design calculation, the figures for lighting design lumens are taken to be 80 07o of initial lumen output, with the exception of high pressure sodium (SON) lamps where a figure of 85R7o is used. • The figures for initial lumen output are the mean values of manufacturers' published figures. The reason for this is that at the general planning stage the supplier is unknown. The cost comparison is as follows: Total cost per lumen — Ax B
where X = the capital cost Y = the energy cost Z = the lamp replacement cost A = the basic downward light output ratio of luminaire lighting design lumens of lamp Total capital cost (X) = (Cost per lamp) + (Cost per luminaire) + (Overall erection cost of each luminaire) The overall erection cost for each luminaire is the sum of the cabling cost (including material, installation and cleating), the cable glanding and terminating cost, and cost of erecting the luminaire. Energy cost (Y) = (Total circuit power) x (Capitalised cost) The capitalised cost is expressed in £/kW. 592
Lamp replacement cost (Z)
z
Design life of installation (lamp cost + labour) Lamp life
This simple calculation allows the designer to plac e the various lamp/luminaire combinations in order o f their economic cost per lumen. Before leaving the general planning stage it m ay be helpful to list, together with the reasons for th e i r choice, some examples of the typical fittings used o n recent conventional and nuclear power stations. The following list is by no means comprehensive, nor is it intended as a mandatory list of equipment for pow er station lighting systems.
High bay applications Gas discharge lamps (mercury and sodium) in high bay reflectors are preferred to fluorescent tubes and tungsten lamps for high bay applications. The 1000 W SON lamp is the most suitable because of its low cost per lumen, and because !ar2:: amounts of light can be provided from a relatively small number of sources. This results in a saving in the capital and running costs, and also a reduction in the maintenance costs. Wherever possible, particularly in the turbine hall, the fittings are suspended from chains at a height that facilitates maintenance from the crane platform, thereby removing the necessity to use scaffolding. Plant areas The problems in the lighting of plant areas are caused by the fact that there can be a multiplicity of different size areas, mounting heights, obstructions, operating conditions and access difficulties. It is advantageous in plant areas to use the minimum number of fittings, i.e., to use high light-output sources (with due regard to glare), and to punch the light from distant positions to those areas where it is required. The positions of these fittings is chosen for ease of access. The use of directional luminaires introduces flexibility and permits alteration of the lighting scheme with the minimum of alteration to the source-positions should there be significant changes in plant size or layout. Although it is difficult to make a general rule to use one particular lamp and luminaire, it is sensible to provide as much light as possible with one type of fitting. The fittings selected for this task are 400 W (preferably) or 250 W SON discharge lamps in directional projector luminaires. In areas where it is not possible to provide illumination from distant positions, 1800 mm fluorescent fittings are used because they may be positioned at low mounting heights. Low headroom applications (switchrooms, meter rooms, relay rooms, telecommunication rooms, compresso r rooms, etc.) In switchrooms and rooms with low equiP ment mounting heights (except cable tunnels and cable
Lighting, heating and small power systems UF = utilisation factor of the luminaire in the
oa(s) fluorescent fittings are used. To reduce stores requirements, the 1800 mm fitting has been selected com parable with the fittings used in the plant t o he reas. a iceess ways, stoirity.tys, cable tunnels, cable flats, etc.
;e areas by their very nature are small and subject i le o cough treatment. The fifth 12s are required to be .Liirabie for low mounting heights and must be of a F.t construction. Low power bulkhead fittings meet t 0[11 these requirements and, additionally, experience 1, has proved that they are less likely to be misapproHaled. For these reasons bulkhead fittings are prefared to 1800 mm fluorescent fittings. In summary the four types of fitting described here, reflectors, directional projectors, 1800 mm Lh bay fluorescent fittings and bulkhead fittings form the mainstay of fittings for power station lighting systems. f
MOM
MF = maintenance factor
The formula can be rearranged to permit the calculation of the number of luminaires required to achieve the specified illuminance: EA FxnxtiFxN1F
As stated previously, the room proportions influence the utilisation factors (UF). The absolute values of room dimensions are not important, it is the relationship between area, perimeter and height of the light source that matters. The room index is a measure of the proportions of the room: LW
Room index —
13.2.4 Detailed planning
(L + W) Hm
Olen the general planning has been completed, de=ailed calculations are required to determine such things as the number of luminaires, the glare index, the final costs, etc. The designer may find at the detailed planning stage, due to the large number of variables associated with the design of lighting systems, that the proposals resulting from the general planning are unsatisfactory in some regard. The design has to be refined by an iterative procedure as part of the detailed &sign process. The starting point for the detailed interior lighting design of a power station is to determine the number of luminaires required to achieve a specified illuminance, i.e., the levels of illumination given in (EGB, GDCD Standard 31. The calculation of average illuminance is performed using the 'lumen method' formula. Until recently, the procedure adopted was to dllow for deterioration of the installation throughout operating life. This was done by introducing a maintenance factor (MF) to represent the effect of dirt depreciation and by using the lighting design lumen (1. DL) figures, rather than initial lumen figures, to represent lamp depreciation. The LDL figure is a nominal value which is representative of the average light output of each type or size of lamp throughout its life. Using this approach the equation for calculating :}me average illuminance is: FxnxNxUFxMF
where
L = the length of the room W = the width of the room Hm = the mounting height of luminaires above the working plane
Let us now consider a typical example using the preceding lumen method of calculation to determine the number of high bay SON fittings required to illuminate the main turbine hall of a power station. The required illumination level from GDCD Standard 31 is 200 lux. The turbine hall dimensions are 130 m x 62 m with the light fittings mounted 28 m above the operating floor level. The lamps selected are 1000 W SON in high bay luminaires. Lighting design lumens of lamp = 102 000 Downward light output ratio, DLOR = 72% 130 x 62
Room index —
(130 + 62) 28
= 1.5 The ceiling and wall reflectances in the turbine hall are 0.3 and 0.1 respectively. From the tables of utilisation factors calculated using the BZ method described in CIBS Technical Memorandum 5, the UF is 0.55. A maintenance factor of 0.8 is used.
A
o. here E -- illuminance, lux = lighting design lumens of the light source = number of lamps per luminaire = number of luminaires A = area to be lit, m 2
200 x (130 x 62)
Number of fittings, N —
102 000 x 0.55 x 0.8
= 36 To achieve an acceptable uniformity of illuminance, the spacing between centres of luminaires (in either 593
Cabling
Chapt er 6
direction) divided by the mounting height must not exceed the maximum spacing/height ratio quoted by the manufacturers for their luminaires (i.e., fitting spacing/height ratio < maximum spacing/height ratio). If this ratio is exceeded in either direction the illuminance will be unacceptably patchy. The maximum spacing/height ratio for the high hay luminaires is 1:1. With the luminaires arranged as shown in Fig, 6.152 the spacing/height ratio = 15.5/28 = 0.5:1 < maximum spacing/height ratio. The procedure of adopting a maintenance factor of 0.8, or whatever other figure seemed appropriate for the situation, is increasingly being abandoned because it gives only a single estimate of the illuminance that will be provided by the installation. The CEGB is considering the adoption of the light loss factor used by the CMS, which represents the total light depreciation at a given time compared to the figure when the installation was brand new and in pristine condition. The light loss factor is the product of three other factors, namely: • The lamp lumen maintenance factor (LLMF) estimates the decline in light output of the light source over a specified time. • Luminaire maintenance factor (LMF) estimates the effect of dirt deposited on or in the luminaire over a set time on the light output of the luminaire. • Room surface maintenance factor (RSMF) estimates the effect of dirt deposited on the room surfaces over a set time on the illuminance produced by the installation, so: light loss factor = LLMF x LMF x RSMF A detailed consideration of this data enables a realistic maintenance factor to be established. By calculating the light loss factor for different times and taking into account the proposed maintenance schedule, it is possible to predict the pattern of illuminance that will be produced by the installation over time (see Fig 6.153). This pattern can be used to estimate the
average illuminance provided by the installation o ver ti me, and hence to determine whether the installation is likely to meet the appropriate design service ill u _ mination recommended in GDCD Standard 31. Substituting LLF for MF in the lumen method fo r mula, the average illuminance on the working plane (x) is given by: E(x) —
Fx x N x LLF Mx) A(x)
where E(x) = average illuminance on working plane, lux = the initial illuminous flux of the lamp lumen = number of lamps per luminaire = the number of luminaires LLF = the light loss factor UF(x)
the utilisation factor of the worki plane
A(x) = the area of the working plane, m
ng
2
The lumen method applies only to regular arrays of luminaires. In the case of directional projector luminaires used in power station plant areas and other irregular layouts the calculation of average illuminance can be inadequate or meaningless. For these arrangements it is necessary to calculate the illuminance at all points of interest due to the individual luminaires. Various means of calculating the direct illuminance are available, ranging from laborious hand calculations to more sophisticated computer methods. The illuminance at a point due to direct light (i.e., ignoring any reflected light) can be calculated by the inverse square law (see Fig 6.154 (a)): E=— d2 where E = illuminance on a plane perpendicular to incident light, lux = the luminous intensity of the source in the relevant direction, cd
4 rn
= distance 0 071
1.
X
* FIG. 6.152 Arrangement of luminaires in turbine hall
594
.
Referring to Fig 6.154(b), if the surface is turned through an angle of 0 from this position, the general relationship becomes: E = (i/d 2 )cos It is often more convenient in practice to measure the height of the source (H) and the horizontal distance away (D). The general formula may be expressed in these terms as follows:
Lighting, heating and small power systems
, 'EARS 7 ,N ASSI,YED 7 7 7
77 L1111 5
SE .EP /FIR
LO33 DbE 70 La LIP E 7 E. , CA1 ON -
1 1,13
L -.JIINA PE :LEAhEe. Al
LUk1,4.AIRE CLEANED AT '2 MCNTi, S
3
KOC1
XC
3G03
,
4101
XCI
HOURS CF JSE
FIG. 6.153 Changes in illuminance with time for different maintenance schedules
la)
(b)
The above formulae assume that the luminaire can be considered as a 'point' source, i.e., the source is small compared with the distance between it and the point of illumination. A luminaire can be considered as a point source if its largest dimension is less than a fifth of the distance from it to the point being illuminated. When this is not the case, the calculation must be modified. Similar formulae exist for 'line' and 'area' sources, and are fully described in specialist design manuals such as the CIBS Code for Interior Lighting. Computers, with suitable software, are ideal for performing the considerable number of calculations involved in determining the illuminance at all points of interest. However, hand calculations when used with discretion, yield sufficient information to allow the design of the lighting installation to proceed. Having designed the installation to provide the correct levels of illumination with an acceptable level of glare, the designer will perform a detailed cost comparison of the final installation to confirm the conclusion of the economic assessment carried out at the general planning stage. 13.2.5 Appraisal
F[G. 6.154 The calculation of illuminance due to
direct light
+ H 2 ) cos 0 or (I cos 2 0)/H 2 si milarly En
I/(D 2 + H 2 ) or (I cos 2 0)/H 2 I/(D 2 + H 2 ) sin 0 or (I cos 2 0 sin 0)/H 2
The final step in the design of a lighting installation is to undertake an appraisal of the system following its completion. In addition to the subjective assessment made by the designer, a photometric survey of the lighting conditions achieved by the installation should be performed and the results compared with the quantitative elements of the design specification (e.g., levels of illumination). If it is found that the final installation does not meet the specified levels of illumination the installation can be modified to provide additional light fittings. The importance of 595
Cabling undertaking such an appraisal is that not only does it provide reassurance that any deficiencies will be discovered and rectified, but it also completes the design by providing feedback on the installation for the benefit of future designs.
13.3 Emergency lighting systems The Fire Precautions Act, 1971 and the Health and Safety at Work Act of 1974 make it obligatory to proadequate means of escape in all places of work and public resort. Emergency lighting is an essential part of this requirement. The CEGB has always recognised the need to provide personnel escape lighting to ensure safe and effective evacuation of buildings in the event of failure of the main AC lighting for whatever reason. All power station lighting systems incorporate personnel escape lighting systems that are either continuously energised or energised immediately on loss of the main AC lighting, so that some form of exit lighting is always available. Certain areas of nuclear power stations cannot be evacuated immediately in the event of an emergency or loss of AC grid supplies. The nuclear reactors of these stations must be shut down safely and monitored to prevent risk to life. To assist in the operation of the essential safety-related equipment on nuclear power stations two additional emergency lighting systems are provided. The first is called the emergency operational lighting. This system, in common with the personnel escape lighting, is a battery-supported system that is continuously energised, or energised immediately on loss of the main AC lighting. ft is required to maintain the effectiveness of the control room and other selected operational areas. The second system is called the essential operational lighting. With this system a selected number of the normal AC light fittings are supplied from a diesel-generator supported power supply. The essential operational lighting takes over from the emergency operational lighting to provide the long term lighting in the control room and other areas containing safetyrelated equipment. The essential operational lighting system is more efficient than the emergency operational lighting system, and provides an enhanced level of illumination to enable the operators to carry out the long term safety duties on loss of the main AC lighting ; These two diverse lighting systems ensure that some operational lighting is always available following loss of the main AC lighting supplies. The dieselgenerators used to supply this lighting are the same diesel-generators that supply the essential safety equipment. On loss of the normal grid supplies these diesels are started automatically, and supplies are restored to the essential loads and the essential operational lighting. Although the essential operational lighting is not directly safety-related it is designed and qualified to the 596
Chapter 6 same standard as the essential plant it srequited, to illuminate. To achieve this, segregated seismicall y qualified lighting systems are provided to guarant ee some functional lighting following a seismic disturbance. The segregation requirements for electrical equip_ ment are given in Section 2.1 of this chapter. The five-stage design process adopted for the d e . sign of the main AC lighting (objectives, specificatio n , general planning, detailed planning and appraisal) i s equally valid for the design of the emergency liehtin9, system. The personnel escape lighting is designed to provide a normal illuminance of 5 lux along the centre line of a clearly defined escape route for a minimum period of 30 minutes. This enables all areas of the station t o be evacuated if necessary. The luminaires are located near each exit and at points where it is necessary t o emphasise the position of potential hazards, such as changes of direction, staircases, changes of floor level, etc. The alternative lighting arrangements considered by the CEGB for the battery-supported emergency lighti ng systems range from the traditional independent DC system with a centralised battery to the self-contained AC fitting where the individual luminaire incorporates the battery, charger and inverter. The self-contained luminaires are self-powered and operate independently from their own batteries in an emergency. Thus, al. though individual luminaries may be destroyed in a fire, the remaining luminaires will be unaffected. Self-contained luminaires are the easiest and mo,r flexible to install but their effective life (i.e., replacement of integral battery, and/or fitting) is 1 :n5 than that of a centralised battery scheme. Also, ma,: :..:nance , and testing of self-contained luminaires is re involved and must be thorough if operation in 'e event of emergency is to be guaranteed. The initial aurae. Lions of this system of ease and flexibility of installation are outweighed by the cost and maintenance difficulties involved in implementing such a system on a power station. In almost all cases, with the exception of the control room, the independent DC system with centralised batteries has been adopted for the personnel escape lighting. It has also been used for the emergency operational lighting on recent AGR nuclear stations. In this system, DC lamps (tungsten or tungsten halogen) are fed from DC distribution boards which. in turn, are supplied via DC contactors from a central battery (see Fig 6.155). Because tungsten and tungsten halogen lamps have a relatively poor operating life, the independent DC system is de-energised under normal operating conditions. It is therefore necessary to arrange for the DC emergency lights to be switched on automatically when the main AC lighting is lost. A low voltage relay monitors the three-phase supply to the AC distribution. When the relay detects that the AC supply has beet lost or fallen to an unacceptable value for half a cycle. the DC contactor closes automatically energising the
Lighting, heating and small power systems
S`C ..7.C.N7sc Top
DC D ■ STP , AU r , 0 ,1 BOARD
In order to achieve an efficient, aesthetically-contoured (i.e., light fittings arranged to follow the li ne of desks and panels) lighting scheme in the control room, emergency operational lighting is prol,ideci by supplying the centre AC fluorescent tubes of the special recessed fittings via dedicated inverters from a batterybacked source. A duplicate feeder arrangement is provided with 50°Ai of the emergency fluorescent tubes connected to each feeder. The lamps are interlaced and supplied from alternate emergency AC distribution centres to guard against a single fault, such as failure of an inverter or charger, rendering sections of the control room inoperative. The personnel escape lighting in the control room is provided by 'light spill' from the emergency operational lighting.
13.4 Lighting of special areas NDEPE NDEN LAMP A
ii(.. 6.I51 Independent DC emergency lighting system
The lighting of some areas within a power station requires special consideration, either because these areas are hostile and hazardous, or the luminaires used are unique to a particular application. 13.4.1 Battery rooms and chlorination plant rooms
p( 'Hilts within half a second. A timer is provided he low voltage relay to cater for the re-strike time catcd with discharge lamps. The timer delays the of the DC contactor on restoration of the \( .tipply until the AC lighting has returned. Duplibatteries and chargers are provided to prevent a ,i0c fault, including a fire, causing the loss of all c,cape lighting. Centralised batteries are used for other DC systems switchgear closing and tripping) and the main•..p..ance procedures for such batteries also apply to the :n,er.=ency lighting batteries and chargers (see Chapter 1. meNency supply equipment). 11iliough the independent DC system has always regarded as uncomplicated and economic, it does I he disadvantage of requiring DC contactors and %oltage relays at each distribution centre. Also rittini2s, which are inefficient, are required LdLiItLOfl :o the normal AC light fittings. A future :lopmerit that is being considered for power station i)( liAting systems is a hybrid of the independent s.,ierti and the self-contained luminaire system. • !hls system, continuously-energised AC fittings with :.:L-4ral inverters are supplied from centralised battery •% , !enis, thus combining the efficiency of AC fluores...::1 itting.s with the advantages of a centralised c . The system is continuously energised and contributes to the illumination level provided iC main AC system. However, before this system he adopted for use as the emergency lighting on • er tations, a detailed study of the reliability of integral inverters must be performed to ensure [he rehability of the new system is equal to that he existing systems. ,
The luminaires used in these areas are corrosion proof to Section 8.1 of CEGB Standard 127304. To prevent the possibility of hydrogen being trapped adjacent to ceiling-mounted luminaires, luminaires in battery rooms are suspended on chains from the ceiling. The fittings are arranged so that they are above clear floor areas and not suspended directly above the battery cells. The switches and sockets are mounted outside the room. 13.4.2 Hydrogen plant (Division 1 and Division 2 areas)
The choice of lamps and luminaires for these areas is either SON lamps in directional reflectors for the main AC lighting with tungsten lamps in bulkhead luminaires for the emergency lighting, or fluorescent tubes in Division I or Division 2 luminaires for the main AC lighting and tungsten lamps in wellglass luminaires (Division 1 or Division 2) for emergency lighting. The choice of fittings is twofold because there are two alternative methods of illuminating a Division 1 or Division 2 area: • By locating no fittings inside the area itself, but providing the light from conventional lamps and luminaires through sealed and toughened glass windows. • By using special fittings located at low level inside the area itself. These fittings must comply with B54683: 'Electrical apparatus for explosive atmospheres'. In selecting a suitable lighting system for these explosive areas, the design must comply with the require597
Cabling ments of CMS lighting guide for 'Hostile and hazardous environments'. 13.4.3 Central control rooms
The lighting scheme in power station central control rooms (CCR) incorporates recessed air handling fittings using 1800 min warm white fluorescent tubes. The fittings are recessed to eliminate glare (either direct or reflected) from control surfaces including indicator glasses. The fittings are positioned to enable the lamps to be changed and the fittings maintained while the plant is running. Maintenance of the control room lighting is effected from below without the use of staging or elaborate access facilities. No light fitting is positioned over a control desk. The recommended configurations for various areas are: • Panel vertical surfaces (front)
A continuous row of luminaires following the contour of the panels and positioned so that there is no specular glare reflected by the polished surfaces of the panels from the luminaire controlling the light directly onto the panel vertical surfaces.
• Control desks
The recessed luminaires are placed in a continuous line parallel to the main axes of the desks (normally square horseshoe-shaped). They are positioned so that there is no specular glare to affect a seated or standing operator at the desks.
• Behind the panels
A continuous row of luminaires is provided which follows the contour of the panels.
Variable illuminance by means of thyristor or switched controlled dimmers is provided to meet the varying needs of the personnel working in the control room, particularly the unit control areas. Care is taken to ensure that the minimum levels of illumination specified for the control room are always maintained. 13.4.4 Hazard warning lights
To meet the requirements of the Department of Trade and Industry and the Ministry of Defence, aircraft obstruction lighting is provided on all obstructions (e.g., chimneys and cooling towers) having a height of 153 m or more above ground level at the site of the obstruction. The warning lights are occulting lights with a special light distribution and a particular mounting arrangement. The requirements of the Department of Trade and Industry, the Ministry of Defence and the construction and mounting arrangement of the warning lights are all fully specified in GDCD Standard 34. In a similar manner, warning lights are required to identify hazards to shipping, such as CW outfall 598
Chapt er 6 structures. The present requirement for shipping haz. ard lights is a white flashing light that flashes o nce every five seconds. However, the CEGB closely consults with the relevant Port and Docks Authority on th e latest requirements for shipping hazard lights. 1 3.5 Supplementary heating and minor power systems The minor power supplies (e.g., small ventilations fans, electrically operated doors, etc., and similar loads up to 30 A) and all heating supplies, are taken from th e minor power fuseboard on each distribution centre, Also, the supply to the 110 V AC power socket fuseboard is taken from the minor power fuseboard, via a centre-tapped 415/110 V transformer. 110 V AC socket outlets are provided in plant area s to supply hand tools, etc., which are used for mai n . tenance. By earthing the centre tap of the 415/110 V transformer output winding and connecting it also to the earth terminal of the apparatus, the line to earth voltages are reduced to 55 V while the Full 110 V supply is available to power the apparatus. As most electric shocks occur between a live part of an equipment and earth, this is a major step in the reduction of the shock risk. The adoption of this system in the construction and mining industries has resulted in dramatic fall in the number of electrical portii:- . fool accidents, and it is now being increasingly ad i in other industries. GDCD Standard 25: Plug , .et outlets and fuse spur units' specifies the requi,-_.:T . c:nts for 110 V sockets for power stations. In addition to the 110 V AC socket outlet syosm, a system of three-phase 415 V socket outlets is r ided to supply the mobile plant utilised in power ,„:Lions. The type of plant envisaged is welding equipment, bolt heating equipment, etc. The use of mobile electrical equipment, irrespective of its size, always introduces additional hazards to a permanent installation. These risks can largely be identified with: • Electric shock from the mobile equipment in the event of a fault within that equipment. • Damage to the trailing cable used to connect the mobile plant to the permanent cabling installation. Both these risks can be minimised if the correct equipment is chosen both for the remote electrical apparatus and for the trailing cable, and its connections. Providing that the conductors utilised are enclosed within an earthed metallic screen and this screen Is of adequate capacity to carry any fault currents that could arise from insulation failure of those conduc tors, then there is no risk of electrocution from contact with the conductors of the installation. Special consideration must be given, however, to the rise ot
Lighting, heating and small power systems h potential of the metallic screening of the reequipment during the instant that the metal , is carryirw earth fault eurrent. Protection nine t rise of earth potential on the casing of the . i 11 be afforded by overcurrent l e appliance Call such) as fuses, or residual current devices in r current operated earth leakage circuitmin o F0llo ■Nim2 investigations by the CEGB into po)sible fault clearance times associated with HBC alf V socket outlets now incorporate re• , t he rent protection devices. The device is specur ,.iieLl to have a tripping current of not greater than n:\ with an operating time not exceeding 30 ms , i l'ie full specification for the '415 V AC fused and 1tched socket outlets (incorporating residual current ,•, ■ r.-oiectiony is given in GDCD Standard 238. The heating of the main areas within a power station proN,ided for by the main heating, ventilating and air(HVAC) system. Supplementary electric ating is provided in areas where it is uneconomic or e opraetical to provide a comprehensive HVAC system. the supplementary heating is designed in accordance .6Ih design memorandum 074/4. This design memoandum gives details of various heating methods availr Jhle, and the temperature and humidity levels to be
13.6 Distribution system
eart
The three types of heaters previously specified for ,e. on power stations are: u • In switchrooms and other areas with low rates of L hange of air, where the air is to prevent condensation, tubular heaters of the type that limit their urface temperature should be used. Control is by means of thermostat and/or humidistat devices, depending on the situation and building construction. • In rooms with very large volumes, it may be im-
practical to use the above tubular heaters because of the large quantities involved. To achieve the heating levels specified in design memorandum 074/4, an heaters may be considered for the purpose. Again, control is by means of thermostat and/or humidistat devices, depending on the situation and building construction. • In areas where comfort of personnel is required, but where space heating is impractical (e.g., semiopen work areas such as garages), radiant heaters of the infra-red type may be used. It is essential that the manufacturer's installation instructions for these heaters are strictly adhered to, particularly concerning mounting height and coverage. Thermostatic control is difficult with this form of heating and care must be taken regarding the positioning of the thermostats. Supplies for supplementary heating systems are taken from the minor power fuseboards on each distribution centre.
13.6.1 General
To illuminate a volume of space, that space can be divided into overlapping spheres, with a fuseboard at the centre of each sphere. The cables radiate from the fuseboard, and the radius of each sphere is the maximum economic length of the cables. The centre of each sphere is known as the 'load centre'. With the large size of lighting and minor power systems in power stations, the aim of this principle is to achieve an economic design of the distribution system and reduction in maintenance by reducing the number of spheres, and therefore fuseboards, to a minimum by fully utilising the capacity of fuseboards and cables. In general, areas requiring lighting, minor power supplies and 110 V power socket outlets are supplied from 'distribution centres'. Areas that do not warrant distribution centres, i.e., areas containing lighting only, are supplied from distribution fuseboards. However, when considering the case for distribution fuseboard versus distribution centre, account must be taken of the number of main feeders that will be required and whether main supplies will be derived from a switchboard or distribution board. Lighting circuitry should be utilised to the maximum and therefore all lighting circuits should be fused wherever possible at 30 A. However, there may be certain lighting and minor power circuits requiring fuses rated at less than 30 A. The maximum economical cable lengths from fuseboard to fitting are dependent upon the volt drop in the cable under starting and running conditions, and the fuse size protecting the cables. 13.6.2 Isolation and switching of individual fittings
Lighting in plant areas is utilised for three basic purposes, namely: • Access. • Inspection. • Maintenance. Traditionally, where it is necessary to provide a high level of lighting for maintenance, temporary lighting is used. In the past, access and inspection have not been differentiated but have both been covered in the normal permanent lighting scheme. However, bearing in mind the current high cost of energy it has been decided on recent projects, where possible, to split these two requirements and to provide separate lighting sub-circuits for 'access' and 'inspection' lighting. Therefore, in those areas where this scheme can be practically and economically used, two AC lighting distribution fuseboards are provided at each load centre, one designated 'access' and one 'inspection'. The 599
Cabling `access lighting is left permanently switched on, and the 'inspection' lighting switched when required by means of a contactor controlled by a switch adjacent to the plant covered by that load centre. ` Access' lighting basically covers walkways and exits to allow free and safe movement around items of plant, and utilises approximately 50n of the total complement of fittings. 'Inspection' lighting uses the remaining fittings and pro%. ides supplementary illumination covering plant items, Because of the nature of the rooms in which fluorescent tubes are used, it is not necessary in some cases (e.g., switchrooms, relay rooms, offices, etc.) to provide illumination at all times. Therefore switches are provided in the sub-circuits to give a simple and flexible arrangment. Switches are 15 A, single-pole, to BS3676: 'Switches for domestic and similar purposes'. Switches are positioned at each entrance to each area with 2-way and intermediate switching as required. En 'industrial' areas, switches are of galvanised steel and surface-mounted. In areas where a 'fair finish' is required, switches are of satin chrome plate and flush-mounted. Current switching capacity is the maximum steady current which may be interrupted, or prospective current which may be made, with a purely resistive (nonreactive) load. Loads, other than of a purely resistive nature, invariably require derating if working life and, in some cases, safe working are to be maintained. An inductive load may cause high voltage and current surges as the magnetic flux collapses. Such voltage surges may cause flashover and damage to insulation. Therefore, for inductive (fluorescent) loads, suitable s witches are always specified. 13.6.3 AC supplies An area of plant (e.g., turbine hall) will be divided for the purposes of lighting, heating and minor power system into zones. Situated as near as possible to the 'load centre' of each zone will be a group of distribution fuseboards known as the 'distribution centre'. Each AC distribution centre is designed to be either floor or wall/column mounted and includes the following: • One distribution fuseboard for the continuously energised lighting. En the areas where switched lighting is to be provided, one distribution fuseboard for 'access' lights and one distribution fuseboard for `insptetion' lights is required. The inspection fuseboard should be fed via a contactor controlled by a switch located adjacent to the plant covered by the corresponding lamps. • One distribution fuseboard for minor power supplies. • One splitter box, to split the incoming cable to feed the lighting fuseboard(s) and the minor power fuseboard.
600
Chapter 6 • One distribution fuseboard for power sockets. • One 415 V/110 V AC transformer fed from th e minor power fuseboard, supplying the 110 V Ac power socket fuseboard. A lamp characteristic which should be considered when planning the main AC lighting distribution system i s the stroboscopic effect. The stroboscopic effect is an illusion which makes a moving object appear stationary, or moving in a different manner from that which it is in fact moving. All lamps operating on alternatin g current exhibit some degree of cyclic variation of light output. It is most significant with discharge lamp s which do not employ a phosphor coating. The problem can normally be reduced, or eliminated, by ha v i ng alternate rows of luminaires fed by different phases of the supply, ensuring that critical areas containing unguarded moving machinery receive illumination in roughly equal proportion from each phase. 13.6.4 DC supplies Each area covered by the DC battery-backed emergency lighting scheme is divided into the same zones as the corresponding AC supplies. A DC distribution centre provides the emergency lighting in that zone. The DC distribution centre is separated from the AC distribution centre to avoid loss of DC supplies in the event of a fire at the AC distribution centre. The DC distribution centres comprise the following: • One distribution fuseboard for personnel escape and emergency operational lighting. • An automatic low voltage relay with a manual override, accommodating a three-phase feed from the associated AC lighting distribution fuseboard. Where 'access' and 'inspection' fuseboards are installed, the three-phase feed shall be from the 'access' distribution board. • One timer linked to the low voltage relay. One DC contactor operated by the low voltage relay in the DC distribution centre. 13.6.5 Cabling The majority of the cables used for the lighting, heating and minor power systems of modern power stations are of the armoured type described in Section 5.4 of this chapter. This method of cabling is compatible with the main station cabling and is less labour intensive to install than conduit and trunking. However there are exceptions to this, for example, where circuits have to be run buried in plaster to give a 'fair finish', or in areas where a multiplicity of terminations is required. In these cases trunking and conduit may be more economical than armoured cables. The AC supply cable to any one AC distribution centre from its switchboard is designed to be segte-
Design and management techniques d from the DC supply cable to the DC distribution , 3iiure associated with that one zone. The segregation in accordance with the segregation ' Class II discussed in Section 2.1 of this chapter. oirernents 1.,: required to . prevent a single fault (fire, missile etc.) causing the loss of both the AC and ‘
Iiltliting in any zone. 14 Design and management techniques
14,1
Introduction
total design and installation process for a cable is illustrated on the flow chart shown in Fig 6. It comprises essentially three phases of work, a . 6 .1 phase, an information issue phase and an jes ar, lIatiofl phase. The quantity of work is very large ti each phase, involving many man years of effort. ;or I he three phases are continuous over periods of several ,ears for a large power station project and overlap m os t of the time. There is an obvious need for a great deal of detailed !darning of all phases of the work and the success of the project depends very much on how well this is Jon C. The CEGB undertakes a greater proportion of the :oial cabling task for a new power station than it does r o r any other system or equipment. It initiates and ndertakes virtually the whole of the design and enu ,lineering work and issues the detailed working face ,n,tructions and drawings to the cable installer. It also rias a large part in organising site installation which k dependent on other contractors in respect of both .1 0:ess and programme. The work involved on a major project covers be:kc een 25 000 and 50 000 cables and more than 1 000 000 ...ire terminations. Each 'cable' and each 'wire' has !o be uniquely designed and identified to ensure that dectrical plant and control and instrumentation equipment functions satisfactorily. The extent of control Jid instrumentation has increased considerably on modern power station projects, with a consequent inJease in the number of cables and wire connections io be made. To manage the design and execution of the cable ‘owract effectively it is essential to have all the or;.iiiisations involved working on a common basis. To Jetermine the basis it is necessary to consider the ■C' hlect of the contract and this can be best defined as:
•ollip/eting the works in the contract strictly in acordance with the commissioning programme of the turron and within the approved budget price. This objective can be made easier to achieve if 1.1 c= works are allocated strictly to specific items of Plant, these allocated packages of works being known as 'systems'. A system may therefore be defined as: The works necessary to bring any one piece of plant 0 a stage whereby it can be commissioned. ,
1
14.2 Planning An essential element in the planning process is a system index, a document which lists every activity within the scope of the contract and which is formulated over the design period or the station. As items of plant are added to the station design and areas of work become apparent, these items are added to the system index. Complex systems are broken down into subsystems and groups and it is essential that a suitable numbering system be adopted. Computers are used for monitoring and control of information and it is therefore important that the system numbering be compatible with the chosen data-handling computer programs. Installation and commissioning dates are established for each individual system. These dates must be flexible and capable of change in order to evolve the final programme of the station. The dates should primarily be derived from the commissioning programme and, whilst it may not be possible initially to give dates to the smaller items, a reasonable estimate should be given using the commissioning programme of previous stations as a guide. Alternatively, 'envelope dates' may be given to specific subsystems leaving the appropriate groups to be dated as the programme evolves. Whilst it will be appreciated that the commissioning programme requirements will take priority over all other aspects, before a system is dated consideration must be given to the question of load resourcing on design and drawing office staff, the cabling contractors management and site labour, the commissioning team and ancillary departments such as quantity surveyors. The dated system index is then used to: • Feed electrical access dates into the civil programme. • Feed access dates for cabling into the mechanical erection programmes. • Feed termination release dates into the mechanical erection programmes. • Inform plant manufacturers of the final dates for design information for circuitry on a system basis. • Inform the drawing office engaged on the design of the cable supporting steelwork grid and the control pair network. It will be appreciated that it is usually necessary to inform the CEGB's civil and mechanical contractors of the date by which access and/or termination releases are required, rather than to ask them the date by which they expect to have access available.
14.3 Design The total design task includes the following elements: • Provision within the station layout of adequate accommodation for electrical equipment and cables. 601
Cabling
Chapter 6
STA T'C'N RCAro' AS KNOWN AT TIME
DESEGN COPASliSS , ON , NG PROGRAMME
R.C•OL:CE S , 5 7 E . A •NOEx
7 DA S S
.PCOPAMmE 4O.:751
C4 L
CNAAC TS
,
G7EM
MECHANICAL PLANT ERE.: TION PPCGRAMLIE OR ACCESS AND , rER MNATiON RELEASE
,140.53 CPA Ai%G.7.FP , CE ST AF , C. ON:. RAC . OR ETC 50145G, kiAILAdl,..- PE 5. -.),,P5ES AHO REDA TE SISTERS NECESGAP ,
MECHANICAL PLANT DESIGN CONTRACTS FOR RELEASE OF DESIGN INFORMATION
MECHANICAL CON TRACTS
ENGINEER IL O DE SIGN SYSTEM
DRAWING OFFICE TO CONVERT SYSTEM DESIGN INTO CABLES AND ACCESSORIES
OUANTITy suRNEyoR FOR PREMEASLREMENT
CONTRACTOR 5TjRQER YATERIAU5
-
JOINT CEGBiCONTRACTOR MANAGEMENT TEAM CALL UP RESOURCES ANO RELEASE SYSTEMS FOR INSTALLATION
'.! ArEAIALS
ACCESS FOR STEEL AND CABLE
TERMINATION RELEASE
PRECOmm SSIONiNG CHECKS
CLEAR DEFECTS
O UANTI TY StiRvEYOR P OST LIEASuREmENT
TAKEOVER
FIG. 6,156 Design and installation process flow chart
602
DESIGN OF STEELwORK GRID AND PAIR NE - Y4CRa
Design and management techniques The design of the cable support steelwork. The accumulation of information from plant contractors to establish types, sizes and quantities o
A rigid approach is necessary to ensure that design clearance freeze dates are met by the various contractors so that cable design information flows at the required time.
f cables.
Cable system design.
14.3.4 Cable systems and electrical circuit design
Electrical .:ireuit design.
Cable systems and electrical circuit design involves a tremendous volume of derailed engineering work to ensure that each circuit and wire is cabled and connected correctly. A large number of staff is involved. The coordination has, therefore, to be very close and responsibilities have to be defined clearly to ensure that efficient working is maintained and design clearance achieved to programme. The introduction of computeraided design techniques into drawing offices for the preparation of all types of electrical diagrams (covering cable block diagrams, schematic diagrams and loop diagrams) has assisted greatly in solving resource problems. Provided that the correct engineering resource has been allocated at the right time, the rate of design clearance of cables and systems is dependent on the progress of the engineering in plant contractors' works and will reflect any plant delays that are occurring. The development of the CEGB's current design procedures has addressed various difficulties which are described as follows:
Scheduling of cables. Routing of cables. Design clearance of cables, i.e., circuit design completed and terminations specified for each cable and
Ore. 14.3.1 Layout
During the initial development of station layout, came routes are planned. These are based on estimated uantities and known major plant locations, i.e., q tehhouse, control rooms and plant areas. Although [he first consideration in station layout is the economical disposition of plant and minimum civil works' ),ts, cabling space provision must be adequate and a c abling needs catered for. The most important of these needs is that the routes must be available with unobstructed access as early a, possible. This implies being able to include them in the early phase of civil construction, with minimum dependence on steelwork and plant erection. One way io achieve this is to locate them in basement areas or tunnels. The alternative of locating them below operating floor level, provides an acceptable technical dlternative especially at estuarine stations where tunnels are costly. ft is also important to provide cable routes hich are as short and simple as possible. To this end, basement cable routes, with electrical plant at around level, should be designed into the layout. 14.3.2 Cable support systems
ables are carried on steelwork and trays installed %%ithin major cable routes. To facilitate design and manufacture, proprietary systems have been developed, iested and approved. Provided access is available, the ihe of these systems should avoid delays in this area.
Electrical circuit design
The process of circuit design consists of the working out of schematics which have then to be converted into detailed connection diagrams. Sometimes in the past, no permanent record of the overall schematic (or loop diagram) was provided; this led to difficulties at site during installation and commissioning and embarrassed station staffs when maintenance, repair or modification was required. The present process for clearing circuit design and producing final information for cable connections involves the preparation and issue of the following information: (a) System flow diagrams
These are logic diagrams and are prepared for all complex systems, e.g., sequence controls, automatic boiler controls, oil burner control systems, etc.
(b) Schematic diagrams 14,3.3 Information from plant contractors
The inforrrtation concerned is of several types, including: • Details of numbers and ratings of plant items. • Circuit and wiring diagrams of equipment. • Termination details.
These are drawn for individual plant items or circuits on a disconnected contact logic basis so that the circuits can be understood and specified correctly. Some are drawn by the CEGB to give guidance to the contractors, e.g., switchgear protection and control, but the majority are prepared by manufacturers for the equipment they are supplying.
(c) Equipment wiring diagrams
These various types of information are required at different times and are associated with different phases of the cabling design task.
These are detailed point to point wiring diagrams prepared for all electrical equipment cubicles, panels, control desks, local equipment cubicles, etc., by the equipment 603
11, Cabling manufacturer. They will be marked up with basic cabling and core information requirements. These are normally drawn on a subsystem basis and will show all marshalling cubicles, junction boxes and connections to plant items for the circuits involved. They do not generally detail the wire numbers.
(d) Cable block diagrams
These are prepared on a system or subsystem basis to co-ordinate all the connections between the various plant items, initiating devices and equipment, and detail all wire numbers and circuit connection requirements. They are drawn to ensure the circuit schematic design is correctly translated into control system wiring and to provide the permanent record of C and I wiring connections.
(e) System circuit diagrams
Provide simplified work face information for the cable contractor on site, scheduling the wire connections for each cable and the jumper connections for each system.
(f) Wire and jumper schedules
The aim is to provide accurate information for fast installation and provide a complete permanent record for the station staff. it meets the stringent requirements for nuclear projects, particularly in the safety consideration of circuit security and segregation.
Cable system design The design of cable systems has become more constrained by segregation rules, especially in nuclear power stations. These rules are determined by both plant operational availability and by safety considerations (especially in the nuclear case). They have been clearly defined and are handled by the computerised cable design methods now used. In fact the necessary quality assurance can only be guaranteed in this area by the use of computerised techniques and their use is a material factor in establishing the safety case for a nuclear power station. The design of control and instrumentation system cables must both achieve technically suitable schemes and also make it as easy as possible to achieve installation programmes. The major technical objective is to improve signal-to-noise ratios, while the programme aim is to permit early installation and termination of as much cable as possible. There is also the aim of reducing cost by the use of large multicore and multipair cables. These aims led to the development of C and I cable system networks using the large trunk multipair cables and marshalling cubicles incorporating jumpering facilities described in Section 5 of this chapter.
Scheduling of cables This work consists of allocating a cable number to a particular cable, deciding its type and listing it on 604
Chapter 6 the computerised cabling schedules. Cable block diagrams are prepared for power and control cables for the various subsystems and groups usirg estimated quantities for cable cores in the case of control cables. The cables can then be scheduled.
Routing of cables To enable a cable to be sized and routed, it is essential that the location of each end is identified o n layout drawings. This work is dependent on the final layout of electrical equipment and manufacturers' plant items. Power cable routing can normally proceed at a reasonable rate, but C and I cable routing is frequently delayed by a lack of plant and C and I information with subsequent heavy peaks of work. The use of a computer speeds up the process and accurately routes cables in conformity with routing rules including segregation. It produces a precise route card for the cable listing all node points, which is of considerable assistance to the site installation work.
Design clearance of cables The 'design cleared' marker can only be allocated to a cable when it is scheduled, sized, routed and full termination details are specified for each core. This will then allow the cable to be fully installed, connected and tested, but when delays occur cables are released for installation where the cable is scheduled and routed, but termination details are not complete. This procedure, however, creates extra recording and work.
1 4.4 Installation and contract management information 14.4.1
Introduction
The cabling installation process on a power station project can be divided into five parts: • Electrical equipment that is part of the cable installation, e.g., junction boxes, distribution boards. • Cable steelwork. • Cable installation. • Cable glanding, terminations. • Cable marshalling and jumpers. The magnitude and complexity of electrical cabling contracts combined with the segregation and quality assurance requirements of power station design, give rise to the need for a sophisticated system of design and management control. Total project information (TPI) is a comprehensive computer-based design and management control system, covering the activities both in the design office
Design and management techniques d at site, including contract planning aids, work face and evaluation. It includes a cable manageinstruction ment section. cabling comprises a number of programs which TPI a single project interface with a common data i- ornt program maintains specific areas of the Each programs involved in this section of TP[ ,idta. The an
,ire as follovss: Basic project parameters. • TOPICO Equipment scheduling. • TOPICI TOPIC2 Cable steelwork/route matrix. • TOPIC2 Cable scheduling and routing. • TOPICS Cable marshalling and jumpers. • TOPIC7 Measurement and stores control. •
• Equipment scheduling All equipment items that are to be either separately erected or cabled are scheduled as separate items within the equipment of the switchboard. For each item of equipment to be scheduled, the group within which each equipment item falls must also be given at the time of scheduling. • Cable scheduling All numbered cables must be scheduled in their appropriate group as going from one equipment item to another. The latter information may be either specified as an equipment item or by an English description. The appropriate gland and termination data must also be given before the cable can be design cleared. • Steelwork The cable carriers (trays, conduits, etc.) that form the cable route matrix must be scheduled for each segment. In addition, tailend steelwork can be designed and scheduled.
\sill be prepared using the CEGB KEY/MASTER
Dam jata entry system as well as the automatic stripping
or data from the CAD system, and engineering detail
from contractors. Outputs are produced partly by the TOPIC programs and partly using the SOCRATES report generator, and in addition there are management graphics facilities. Outputs can be requested by the users. On-line interrogation of the data can be achieved usmg he MANTIS screen displays which run under CICS.
14.4.3 Designing An automatic cable routing and sizing process is an integral part of the overall Tlpf system. Planning
14.4.2 The aims and functions of TPI cabling
The key target dates are assigned to commissioning systems based on the project master commissioning programme. This data may either be generated automatically from critical path network programs or explicitly input. Dates can be assigned to the following events:
De aims and functions are as follows:
• Design completion.
• Scheduling.
• Access for erection.
• Designing.
• Termination release/cable early start.
• Planning.
• Cable start.
• Organising.
• Cable finish.
• Commanding.
• Cable latest finish — jumper start.
• Co-ordinating.
• Commissioning complete — jumper finish.
• Monitoring. • Valuation. • Reporting. Scheduling [he following basic design data is recorded within the
'
:ern and forms the nucleus of the cabling area of
he database:
• Plant scheduling
The areas of plant may be split separately erectable/commissionable areas based on a hierarchical breakdown of systems, subsystems and groups; the concept being that a subsystem comprises a major commissionable entity. For example, systems are boiler, turbine-generator, etc., subsystems are a FD fan, turbine barring gear, etc., and groups are single drives such as jacking oil pumps, etc. into
The estimated number of cables and jumpers in each system or subsystem may also be input as a basis for the initial plans. Subsequently the site joint planning team takes into account improved information, obtained from questionnaires as the project proceeds, to review and progressively refine the dates. This is normally done by assigning dates at group level. This is a continuous process from the long term (16 weeks plus) to the short term and immediate work programmes. Organising
The organisation depends upon the control of resources, both material and labour, to match the current work programme and access. This is done by arranging the cables, terminations and equipment into work packages. 605
Cabling Details of all material orders and deliveries are entered into TPI. In conjunction with the figures derived from progress data, these form the basis of a stock control system which compares quantities with requirements computed from the scheduled quantities. The labour resources required for the current work programme are computed from the estimated labour content of each task to be performed by the contractor. This allows the joint planning team to ensure that a consistent level of work is released to the contractor and that the material required is available.
Commanding The instructions to the contractor (which are not intended to overcast contractual responsibilities) are the working instructions and are issued as follows, all out-
standing work released to the contractor is the subject of a work release and is listed on the current schedules. Work face instructions for all of these tasks are computer produced in the form of work cards bearing all the necessary information to carry out the task. For example, cabling work cards state full details of the cable type, route, glands and methods of installation. Completed work can be recorded on the work cards which can then be used as computer input documents. Work cards are produced for the following tasks: • Steelwork supports.
Chapter 6 • Cable terminations. • Jumpers installed. • Equipment erections. • Material delivery. This information will normally be input by the quantity surveyors. Valuations of material delivered, material used and labour content value for either a sp ec ifi c valuation period or for the whole of the contract to date may be produced. The latter is known as cumulative valuation. Cable measurement cards are used to assist in the task of cable measurement. They show any outstanding measurement task, i.e., installed and not measured, together with any measurements previously recorded.
Reporting An important aspect of the aid to management al. forded by TPI is the quality of reporting that is possible. In addition to special ad-hoc enquiries, there are routine reports that can be produced showing the progress and status of the contract works against programme. Management summaries can be produced showing the total work done on each section of the contract. These may also be produced in graphical form so that current trends can be analysed.
• Steelwork installation trays/trunking. • Cable installation. • Equipment installation. • Termination instructions. • Jumper instructions. The site joint planning team monitors progress on work packages and work cards.
Monitoring Report venerators are used to summarise and display data in a manner enabling the management team to monitor and analyse design and site activities. During the design phase, the cable route matrix segment usage and control cable core usage can be monitored allowing advantageous design changes to be made prior to installation. During the site phase progress, costs and productivity can all be kept under review.
Valuation
15 References (11 I EC287: Calculation of the continuous current rating of cables . 1982
[2) GDCD Standard 17: 6350/11000V extruded solid insulation cables: May 1978 [3]
BS6346: Specificati,)a for PVC-insulated cables for electricity supply: 1969 (1977)
[4]
ERA Report 69-30: Current rating standards for distribution cables: Part 3: Sustained current ratings for PVC insulated cables to 13S6346: 1969 (AC 50Hz and DC)
[5]
CERL Report RD/LN 197/75: CURB03 computer program: Three-phase power frequency impedance characteristics of single-core power cables with special reference to current sharing between cables in parallel: 1976
[6]
BS2692: Part 1: Specification for current-limiting fuses: 1986
[ 7 1 BS5907: Specification for high voltage fuse-links for motor circuit applications: 1986 1 8 ) BS88: Part 2: Supplementary requirements for fuses of standardised dimensions and performance for industrial purposes: 1975(1982) ( 9 1 IEE Wiring Regulations: 15th Edition 1981: Regulation 43Protection against both overload and short circuit currents [10] ESI Standard 44-3: Electric motors — specification (3300V and above), 1980
The system will accept measurement information for the following:
(11] ESI Standard 44-4: Electric motors — specification (415V and below, 0.75 kW and above), 1980
• Steelwork quantities and supports installed.
[12]
BS5000: Part 40: Motors for driving power station auxiliaries: 1973 (1984)
• Route matrix segment lengths.
[13]
BS4999: Part 41: Specification for general requirements for rotating electrical machines — General characteristics: 1977
[14]
BS4999: Part 101: Specification for general requirements for rotating electrical machines — Tolerances: 1972
• On-matrix cable tail lengths. • Off-matrix cables. 606
References Bs53l t: Part 2: Specification for AC circuit-breakers of rated (... wItage above 1 kW — Rating: 1976 .161
BS5424: Specification for controlgear for voltages up to and ncluding 1000 V AC and 1200 V DC: 1977 FiS147: Section 2.3: Specification for thermal electrical relays: 198-1
I
:111
skinIng Regulations: currently 15th Edition 1981; 16th lEE sued Edirion to be i s DCD Standard 197: Cable supporting steelwork: April 1979 c.; BS3692: Specification for 1S0 metric precision hexagon bolts, ..,:rews and r,u(s. NIetric units: 1967
'21] CDCD Standard 216: Cable cleating arrangements Burki A. N. and Sabine A. M.; Connecting solid-conductor aluminium cables in terminal boxes: The Engineer: December 1963 Solars P. M. A.: Wire wrapped joints — a review: Electrocomponent science and technology: Volume 1, pp 17-25: 1974
1241 BS476: Part 8: Fire tests on building materials and structures — test methods and criteria for the fire resistance of elements of building construction: 1972 [25] BS476: Part 4: Fire tests on building materials and structures — non-combustibility test for materials: 1970 (1984) 1261 BS476: Part 7: Fire tests on building materials and structures — surface spread of flame tests for materials (271 Alderton J. R., Anderson P. C., and Cakebread R. J.: Calculation and measurement of the earth impedance of an eh.. substation: Proc IEE, Vol 125, No. 12: December 1978 [281 IEEE Standard 80: IEEE guide for safety in substation grounding: 1986 [29]
Tagg G. F.: 'Earth resistances': George Newries, London: 1964
[30]
Wenner Dr. F.: Scientific Paper 258: Bureau of Standards: 1915
[31]
Engineering Recommendation S34: A guide for assessing the rise of earth potential at substation sites: May 1986
607
Cabling
Chapter 6
Appendix A
Values of resistance and reactance for single-core elastomeric-insulated cables (90°C maximum conductor temperature)
Armour
Conductor
Cable type
Equivalent star reactance at 50 Hz, pf/trn
DC resistance at 20 ° C, 4/rn
129
158
200
60.5
79
142
170
77.8
100.5
150
110
77.8
100.5
150
110
AC DC resistance resistance at at 20 ° C, pfl/m 90 ° C, ;.I.S1/m
It kV Cables Single-core 300 mm 2 Single-core 500 mm 2
100
3.3 kV Cables Single-core 2 400 mm 415 V Cables Single-core 400 mm 2
Note:
608
Equivalent star reactance values are for a single cable per phase laid in flat formation
Appendix B
Appendix B
Values of resistance and reactance for multicore PVC-insulated cables (70°C maximum conductor temperature)
Armour
Conductor AC DC resistance resistance at at 20 ° C, itillm 70 ° C, ,itil/m
Cable type
Equivalent star reactance at 50 Hz, Aft/m
DC resistance at 20 ° C, 1. 11/m
3.3 kV Cables 3-core 150
mm 2
206
248
80.0
240
3-core 240
mm 2
125
151
76.5
150
2-core
2.5 mm 2
7410
8866
100.0
9100
3-core
2.5 mm 2
7410
8866
100.0
8800
4-core
2,5 mm 2
7410
8866
100.0
7900
2-core
4
mm 2
4610
5516
98.5
7500
3-core
4
mm 2
4610
5516
98.5
7000
4-core
4
mm 2
4610
5516
98.5
4600
2-core
6
mm 2
3080
3685
93.5
6800
3-core
6
mm 2
3080
3685
93.5
4600
4-core
6
mm 2
3080
3685
93.5
4100
2-core
16
mm 2
1910
2295
86.0
1 40
3-core
16
mm
2
1910
2295
86.0
130
4-core
16
mm 2
1910
2295
86.0
1200
2-core
35
mm 2
868
1043
82.0
1400
2
1100
415 V Cables
3-core
35
mm
868
1043
82.0
4-core
35
mm 2
868
1043
82.0
960
2-core
70
mm 2
443
532
79.0
570
3-core
70
mm 2
443
532
79.0
480
4-core
70
mm 2
443
532
79.0
420
3-core 120
mm 2
253
304
77.0
280
4-core 120
mm 2
253
304
77.0
240
3-core 185
mm 2
164
197
77.0
230
4-core 185
mm 2
164
197
77.0
150
3-core 300
mm 2
1 00
120
76.0
mo
4-core 300
mm 2
100
120
76.0
120
The constant mass temperature coefficient at 20 ° C per kelvin are: Copper
= 0.00393
Aluminium
= 0.00403
Galvanised steel wire
= 0.0045
Note:
2 Cables up to and including 6 mm have copper conductors and steel wire armour.
Cables 60 mm 2 and larger have aluminium conductors and armour.
609
TIP Cabling
Chapter 6
Appendix C
Current ratings for elastomeric-insulated cables The current ratings are based on a maximum conductor temperature of 90 ° C with ambient temperature of 25 ° C, with single-point bonding
and no core transposition. Current rating, A Cable type
Direct in the ground
In singleway ducts
Single-core 300 mm 2
500
480
675
Single-core 500 mm 2
645
610
900
575
550
785
575
550
785
In air
11 kV Cables
3.3 kV Cables Single-core 400 mm 2 415 V Cables Single-core 400 mm 2
Note:
610
All cables have stranded aluminium conductors
Appendix ID
Appendix
D
Current ratings for PVC-insulated cables ° The current ratings are based on a maximum conductor temperature of 70 C
and an ambient temperature of 25 ° C.
Current rating, A Cable type
Direct in the ground
In singleway ducts
In air
3.3 kV Cables
3-core 150
mm 2
257
217
265
3-core 240
2
338
285
361
2-core
2.5 mm 2
41
34
33
3-core
2.5 mm 2
35
29
28
4-core
2.5 mm 2
35
29
28
2-core
4
mm 2
55
45
44
3-core
4
mm 2
47
38
38
4-core
4
mm 2
47
38
38
2-core
6
mm 2
69
57
56
3-core
6
mm 2
59
46
4-core
6
mm 2
59
48
48 48
2-core
16
mm 2
91
75
77
3-core
16
mm 2
77
62
65
4-core
16
mm 2
77
62
65
2-core
35
mm 2
142
115
120
3-core
35
mm 2
120
97
104
4-core
35
mm 2
120
97
104
2-core
70
mm 2
209
170
185
3-core
70
mm 2
176
144
161
4-core
70
mm 2
176
144
161
3-core 120
mm 2
243
199
232
4-core 120
mm 2
243
199
232
3-core 185
mm 2
309
254
306
4-core 185
mm 2
309
254
305
3-core KO
mm 2
407
338
421
4-core 300
mm 2
407
338
421
mm
415 V Cables
Notes:
3.3 kV cables have solid aluminium conductors. 415 V cables with nominal conductor areas of 2.5 mm 2 , 2 2 4 mm and 6 mm have stranded-copper conductors. All other 415V cables have solid aluminium conductors.
611
Cabiing
Chapter 6
Appendix E
Rating factors for variations in thermal parameters Rating factors for variation in ambient air temperature
(a) Maximum conductor temperature 70 ° C Air temperature,
°
C
Rating factor (maxhnum conductor temperature 70 ° C)
25
30
35
40
45
50
55
1.00
0.94
0.88
0.82
0.75
0.67
0,58
25
30
35
40
45
50
55
1.00
0.95
0.91
0.86
0.80
0.75
0.69
Lb) Maximum conductor temperature 90 ° C Air temperature,
°
C
Rating factor (maximum conductor temperature 90 ° C)
-
Rating factors for variation in ground temperature for cables buried direct in the ground.
(a) Maximum conductor temperature 70 ° C Ground temperature,
°
C
Rating factor (maximum conductor temperature 70 ° C)
20
25
30
35
40
0.95
0.90
0.85
—
—
20
25
30
35
40
0.97
0.93
0.89
0,86
0.82
(b) Maximum conductor temperature 90 ° C Ground temperature,
°
C
Rating factor )maximum conductor temperature 90 ° C)
612
Appendix E
Appendix E (cont'd)
Rating factors for variations in thermal parameters Rating factors for variation in ground temperature for cables laid in ducts
(a) Maximum conductor temperature 70 ° C Ground temperature,
°
C
Rating factor (maximum conductor temperature 70 ° C)
20
25
30
0.95
0.90
0.85
20
25
30
0.97
0.93
0.89
lbl Maximum conductor temperature 90 ° C Ground temperature,
°
C
Rating factor (maximum conductor temperature
90°C) Note:
The rating factors in the following tables may be taken to be the same for maximum conductor temperatures ° of 70 ° C and 90 C respectively.
Rating factors for variation in depth of laying direct in the ground
3.3 kV and 11 kV cables
415 Volt cables Depth of laying, m
Up to 50 mm 2
0.50
1.00
Above 300 mm 2
Up to 300 mm 2
Above 300 mm 2
1.00
1.00
-
-
70-300 mm
0.60
0.99
0.98
0.97
-
-
0.80
0.97
0.96
0.94
1.00
1.00
1.00
0.95
0.93
0.92
0.98
0.97
1.25
0,94
0.92
0.89
0.96
0.95
1.50
0.93
0,90
0.87
0.95
0.93
613
Cabling
Chapter 6
Appendix E (cont'd)
Rating factors for variations in thermal parameters Rattng factors for variation in soil thermal resistivity
(a} Cables laid direct in the ground
Nominal area of conductor
Ground thermal resistivity K.m/W 0.8
0.9
1.0
1.5
2.5 mm 2
1.09
1 07
1.04
4.0 mm 2
1.10
1.07
1.05
6.0 mm 2
1.10
1.07
16
mm 2
1.12
35
mm 2
70
2.0
2.5
0.94
0.86
0.80
0.94
0.85
0.79
1.05
0.93
0.85
0.79
1.08
1.05
0.93
0.84
0.77
1.13
1.09
1.06
0.92
0.83
0,76
mm 2
1.14
1.09
1.06
0.92
0.83
0.75
120
mm 2
1.14
1.10
1.06
0.92
0.82
0.75
150
mm 2
1.14
1.10
1.06
0.92
0.82
0.75
185
mm 2
1.14
1.10
1.06
0.92
0.82
0.74
240
mm 2
1,15
1,10
1.07
0.92
0.81
0.74
300
mm 2
1.15
1.10
1.07
0.92
0.81
0.74
0.73
Multicore cables
Single- core cables
614
300
mm 2
1.17
1.12
1.07
0.91
0.80
400
mm 2
. 1.17
1.12
1.07
0.91
0.80
0.73
500
mm 2
1.17
1.12
1.07
0.91
0.80
0.73
Appendix E
Appendix E (cont'd)
Rating factors for variations in thermal parameters Rating factors for variation in soil thermal resistivity fbi Cables laid in ducts
Ground thermal resistivity, K.m/W
Nominal area of conductor
0.8
0.9
1.0
1.5
2.5 mm 2
1 03
1.02
1.02
0.98
4.0 mm 2
1.04
1.03
1.02
0.97
6.0 mm 2
1.04
1.03
1.02
0.97
16
mm 2
1.04
1.03
1.02
0.97
35
mm 2
1.05
1.03
1.02
0.96
70
mm 2
1.05
1.04
1.02
0.96
120
mm 2
1.06
1,04
1.03
0.95
150
mm 2
1.06
1.04
1.03
0.95
185
mm 2
1.07
1.05
1.03
0.95
240
mm 2
1.07
1.05
1.03
0.95
300
mm 2
1.07
1.05
1.03
0.95
2.0
2.5
_
Single-core cables
300
mm 2
1.11
1,08
1.05
0.93
400
mm 2
1.11
1.08
1.05
0.93
500
mm 2
1.11
1.08
1.05
0.93
RES%88CD 49 CD CO CO 49
oo
o . . .cDo
Muir/core cables
0.91 0.90 0.90 0.88 0.87 0.86 0.85 0.85 0.84 0.84 0.83
0.79 0.78 0.78
Rating factors for variation in depth of cables laid in ducts
415 Vo t cables Single-core
0.50
1.00
0.60
0.98
0.80
0.95 0.91
1.50
0.89
Single-core
Multicore
_
_
O
0.93
1.25
Multicore
ci
1.00
3.3 kV and 11 kV cables
8RER TA
Depth of laying, m
-
-
1.00
1.00
0.98
0.99
0.95
0.97
0.94
0.96
615
Cabling
Chapter 6 ..
Appendix F
Cross-sectional area of armour wire 475 V 3.3 kV and 17 kV single-core power cables Nominal cross-sectional area of conductor
Cross-sectional area of armour wire, mm 2
11 kV Cables
Single-core 300 mm 2
103
Single-core 500 mm 2
169
3.3 kV Cables
Single-core 400 mm 2
153
415 V Cables
Single-core 400 mm 2
153
All cable sizes have round aluminium armour wire
415 V and 3.3 kV mutt/core power cables to 8S6346
Nominal cross-sectional area of conductor 2 mm
Cross-sectional area of armour wire/strip mm 2 2-core 2 mm
3-core 2 mm
4-core 2 mm
2.5
17
19
20
4
21
23
35
6
24
36
40
16
23
26
29
35
24
30
34
70
56
67
78
120
N/A
117
136
185
N/A
143
214
300
N/A
237
271
2.4 mm 2 , 4 mm 2 and 6 mm 2 cable sizes have steel wire armour 16 mm 2 and above cable sizes have aluminium strip armour
616
.....M1
Appendix G
Appendix G
415 V motor parameters and selected fuse sizes
Rated output kW
Nominal starting current A
Maximum starting current A
Starting t ime s
2x Starting ti me s
Full load current A
Fuse size
0.75
11.0
13.1
3.1
6.2
1.7
10 A
1.1
16.1
19.3
3.2
6.4
2.5
12 A
1.5
21.9
26.3
3.2
6.4
3.3
16 A
2.2
32.1
38.6
3.3
6.6
4,4
20 A
3.0
40,9
49,1
3.4
6.8
6.1
32 A
4.0
54.5
65.4
3.5
7.0
8.1
40 A
5,5
75.0
90.0
3.7
7.4
11.1
50 A
7.5
96.0
115
4.0
8.0
13.9
63 A
11
141
169
4.5
9.0
20.5
80 A
15
192
230
5.0
10.0
27.9
100 A
18.5
224
267
5.5
11.0
32.3
125 A
22
266
320
6.0
12.0
38.4
160 A
30
363
436
7.0
14.0
52.4
500 A
37
448
537
8.0
16.0
64.6
250 A
45
513
616
9.0
18.0
75.0
315 A
55
627
753
10.4
20.8
91.7
315 A
75
856
1027
13.0
26.0
125.1
500 A
90
1027
1232
15.0
30.0
150.1
630 A
110
1194
1432
15.0
30.0
178.9
630 A
132
1432
1719
15.0
30.0
214.7
800 A
150
1628
1953
15.0
30.0
244.0
800 A
617
Cabling
Chapter 6
Appendix H
Maximum cable route lengths Steady state voltage regulation — 1% Motor staring voltage regulation —15% Ambient air temperature 25°C Motor rated output
618
415 V AC motor circuits
Fuse rating Cable size 1
mm 2
Route length m
Cable size 2
,m2
Route length m
231
—
—
157
—
kW
A
0.75
10
2.5
1.1
12
2.5
1,5
16
2.5
115
4
185
2.2
20
2.5
78
4
125
3.0
32
2.5
61
4
99
4.0
40
2.5
46
4
74
5.5
50
4
53
6
80
7.5
63
6
61
16
99
11
80
16
67
35
144
15
100
16
48
35
1 05
18.5
125
35
88
70
168
22
160
35
74
70
141
30
200
35
53
70
102
37
250
70
82
120
138
45
250
70
69
120
117
55
315
70
55
120
95
75
400
120
68
185
100
—
Cable size 3
mm
2
Route length m
Appendix H
Appendix H (cont'd)
Maximum cable route lengths
Three-phase and neutral distribution feeder circuits
F use rating
Cable size 1
A
mm
2
Cable size 2
Route length m
Cable size 3
Route length mm 2
m
mm
2
Route length m
10
2.5
45
12
2.5
37
4
61
16
2.5
27
4
45
6
68
20
2.5
21
4
36
6
54
25
2.5
16
4
28
6
42
32
4
21
6
32
16
54
40
6
25
16
42
35
92
50
16
33
35
73
70
139
63
16
25
35
57
70
109
BO
35
44
70
85
120
142
100
35
34
70
67
120
112
125
70
52
120
89
185
128
160
120
68
185
99
300
144
200
120
53
185
78
300
114
250
185
61
300
90
2-185
128
315
300
70
2-185
101
2-300
146
400
300
54
2-185
78
2-300
114
619
Cabling
Chapt er 6
Appendix I
Main protection for feeder and motor circuits
System voltage kV 11
Application
Fault current breaking device
Feeder circuits (a) Outgoing transformer
Air circuitbreaker
High set instantaneous overcurrent and restricted earth fault, IDMT overcurrent.
lb} Interconnector
Air circu:tbreaker
Circulating current, IDMT overcurrent and earth fault.
Motor circuit
3.3
Main protection
High set overcurrent and instantaneous earth fault, thermal overcurrent with single-phasing.
Feeder circuits above 1 MVA (a) Outgoing transformer
Air circuitbreaker
High set instantaneous overcurrent and restricted earth fault, extremely inverse overcurrent.
Ibl Interconnector
Air circuitbreaker
Circulating current, IDMT overcurrent and earth fault.
Motor circuits above 1 MW
Air circuitbreaker
High set instantaneous overcurrent and earth fault, thermal overload with singlephasing.
Outgoing transformer
Fused switching device
Fuse to BS2692: Pt 1, (61 high set instantaneous overcurrent and restricted earth fault, extremely inverse overcurrent.
Motor circuits / MW and below
Fused switching device
Fuse to 855907, (71 high set instantaneous overcurrent and earth fault, thermal overload with single-phasing.
Feeder circuits above 0.33 MVA (i nterconnector)
Air circuit-breaker
Circulating current differential earth fault.
Feeder circuits 0.33 MVA and below
Fuse
Fuse to BS88: Pt 2 [81
Motor circuits above 50 kW
Fuse/contactor
Fuse to 13588: Pt 2 thermal overload with singlephasing, definite time high set earth fault.
Motor circuits 50 kW down to 1.5 kW
Fuse/contactor
Fuses to BS88: Pt 2, thermal overload with singlephasing.
Feeder circuits 1 MVA and below
0.415
620
Appendix J
Appendix J
Advantages and disadvantages of various lamps used for lighting power station interiors
Advantages
Type of lamp ,Tubular fluorescent
High pressure mercury discharge
(a)
I mmediate light output and restrike.
Ibl
Low surface brightness permitting low mounting height.
(c)
Good colour rendering.
Icl)
Long life l5000-10 000 hours) depending on type, switching cycle, etc.
(a)
Long life (5000.-10 000 hours) depending on type, rating, switching etc.
ft))
Discharge lamp rating higher than fluorescent, therefore high lumen output per lamp.
Ifluorescent) MBF — Arc tube and fluorescent coating on the inside of outer envelope MBFR — An MBF lamp in which part of the outer envelope has an inner reflecting coating .
(c) Light may be provided from distant positions using directional projectors.
Disadvantages (a)
Rating of /amp low, typically 85 W. Therefore lumen output per fitting low. More fluorescent tubes needed than discharge lamps in any one area. This increases maintenance problems.
(a)
Higher rated lamps require high mounting height to avoid glare_
It3)
Run-up period to full light output of about 4 minutes.
lc)
Loss of output occurs when supply voltage falls below 80% of nominal voltage.
(d)
Re-ignition after about 10 minutes on loss of output,
(a)
High mounting height required to avoid glare.
(b)
Run-up period to 90% of full li ght output in about 5 minutes.
Idi Acceptable colour rendering.
MO pressure mercury discharge ( Metal halide) MBI — High pressure mercury discharge lamp with metal halide additives in arc tube and clear outer envelope. MBIF — An Mal lamp with a fluorescent coating on inside of of outer envelope
le)
Operation in any position. position.
(f)
Can withstand prolonged vibration.
(a)
Long life (5000-10000 hours) depending on type, rating, switching cycle, etc.
WI
High lumen output per lamp.
(c)
Light may be provided from accessible distant positions using directional projector.
(c)
Loss of output occurs when supply voltage falls below 80% of nominal voltage.
(d)
Good colour rendering.
Id)
Re-ignition after about 10 minutes on loss of output.
(e)
Can withstand prolonged vibration.
(el
Restrictions on operating position.
621
Cabang
Chapter 6
Appendix J (cont'd)
Advantages and disadvantages of various lamps used for lighting power station interiors
Advantages
Type of lamp High pressure sodium
SON — A high pressure sodium discharge lamp with an arc tube in an outer envelope. SON-R, A SON lamp with an internal reflecting coating.
Disadvantages
fal Long life 16000-12 000 hours) according to rating, etc.
(al High mounting height required to avoid glare.
fb) High lumen output per lamp.
03) Run-up period to 90% of light output in about 5 minutes.
lc) Light may be provided from accessible distant positions using directional projector.
lc) Loss of output occurs when supply voltage falls below 80% of nominal voltage.
(d) Operates in any position. (el Can withstand prolonged vibration.
Id) Re-ignition within 1 minute following loss of output, lel Colour has high yellow and red colours but all colours distinguishable.
Tungsten filament
(a) Does not require any control gear and operates from either an AC or DC supply.
(a) Larger ratings require high mounting height to avoid glare.
(b) I mmediate light output.
lb) Limited life only 1000-2000 hours.
1c) Good colour rendering.
(c)
Poor light output. Light output and life sensitive to small voltace variations.
Id) Operates in all positions. (d) Adversely affected by vibration. Tungsten halogen
Ca
Does not require any control gear and operates from either an AC or DC supply.
(b) Immediate light output. Ic) Good colour rendering. Longer life and higher lumen output than tungsten filament but still relatively poor (20004000 hours).
622
la) Larger ratings require high mounting height to avoid glare. Light output and life sensitive to small voltage variations. (c) Adversely affected by vibration. (d) Some restriction on operating position.
CHAPTER 7
Motors Introductio
n
Types and performance of motors Cage lnduction motors 2l 2 2 Sill:31ing induction motors 2 3 AC commutator motors 2 4 Variabie-speed AC converter drives Cycloconverter 2 4 1 Slip-energy recovery systems 24 2 2 4 3 Voltage source converter Current source converter 2 44 2 _s 5 l).ilse-vvidth-mcdulated converter 2 5 DC motors 3 Design and construction 3 1 Mechanicaf construction 32 Types of enclosure 3 3 Methods of cooling 3 4 'vVindingS 3 5 Insulation systems 3 6 Bearings 37 Terminal boxes 4 Technical requirements
1 Introduction i 'tc modern power station requires a wide range of motors ranging from small power motors up motors as large as 15 MW. There are about 2000 . 'lots in a typical power station. Their total installed .. T.L..Liv is between 5 070 and 10 07o of the station MW depending on the type of station, e.g., nu. c.ir. coal- or oil-fired, and on the type and number motor-driven auxiliaries. Whilst most motors in modern power station are of the cage induction •.; , c. others are also used when there is a technical 'r economic need. Examples include variable-speed -prir42 induction motors for boiler feedpump drives, ;)( ,'uolors for turbine-generator standby lubricating pumps, two-speed cage induction and converter-fed , i .iriable-speed AC motors for drives such as boiler - -, fiqtht fans, barring and the low speed facility for circulators on advanced gas cooled (AGR) nuclear FhiS chapter examines typical auxiliary drive requireand the selection of the motors used. It considers
.,e
lunctional requirements and the effect of these on moor design, constructional features and technical
5 Power station auxiliary drives 5.1 Boiler feed pumps 5.2 Coal- and oil-fired boiler units 5.2.1 Draught plant 5.2.2 Milling plant 5.3 Nuclear reactors — AGR 5.3.1 Gas circulators 5.4 Nuclear reactors — PWR 5.4.1 Reactor coolant pumps 5.4.2 Safety-related drives 5.5 Circulating water pumps
6 Testing 7 Future trends 8 References 9 Additional references 9.1 ESI Standards 9.2 CEGB Standards 9.3 British Standards
9.4 IEEE Standards 9.5 IEC Recommendations
performance. Many textbooks and technical papers are available to the reader on detailed motor design, theory, insulation, etc., and such theory is not repeated in this chapter. Some of these aspects are, however, dealt with insofar as they are necessary to describe particular features of the motors, to explain the functional needs and to portray modern practice.
2 Types and performance of motors There are large numbers of small power (formerly known as fractional horsepower) motors used, e.g., sootblowers, servo motors, instrument drives, etc. These types are not described here. Their technical requirements are specified in CEGB Standard 44011 Electric motors — small power and in BS5000, Part 11, Small power electric motors and generators. Five types of motor are considered: • Cage induction motors. • Slipring induction motors. • AC commutator motors. 623
Motors
Chapter 7 motors because of limitations on starting current j rn _ posed by their electrical power supply system, p ower stations have auxiliary power systems backed by hj oh MVA infeeds and even the largest cage inductio'n motors used in these stations can usually be started direct-on-line. High values of starting current also present problems in that the stator windings must be designed to withstand the electromechanical forces produced by the starting current. The windings m ust also be designed to meet the temperature rise durino starting, which may be considerable, particularly f or the rotor cage windings if a high number of starts per hour is required or the driven load has high inertia. Table 7.1 gives maximum values of starting current permitted with CEGB practice. These values compl y with BS4999, Part 41. The motor torque-speed characteristics must be d e . signed to meet the requirements of the driven l oad under the most arduous conditions of service. Th e torque requirements may in some cases present difficulties to the motor designer since the maximum permitted value of starting current (see Table 7.1) affe cts the starting and maximum torque values obtainal from a given design. From a study of the equivalt circuit theory of induction motors (see Alger 1951 [IL 1970 [2], and Say 1983 [3]) it will be apparent th,it the starting torque and current characteristics can be controlled by varying the values of rotor resistance and
• DC motors. • Variable-speed AC converter drives. Other types of motor not dealt with in detail include li near motors which have, for example, been used on cranes and sliding doors, synchronous motors and mo[ors for glandless pumps of the wet-stator winding or of Me canned typo. Tcelmi,:al requirements of motors for glandless pumps are given in CEGB Standard 620106, Glandless pump/motor units.
2.1 Cage induction motors Cage induction motors are very reliable, since the rotors are of robust construction and have no sliprings, commutators or brushes. They are relatively low in cost and have high operating efficiency; their simplicity and reliability has led to their extensive use for power station auxiliary drives. A disadvantage of the cage induction motor is the large starting current, which is about 5 to 7 times normal full-load current. This presents voltage drop problems to the electrical supply system to which it is connected and can create some difficulties in providing adequate electrical protection, e.g., overcurrent and short-circuit protection. Whereas many industrial users have to restrict the power rating of cage induction
TABLE
7.1
Ratio of starting (locked rotor) kVA to rated output kW
Rated voltage
Rated output (kW)
Ratio of starting (locked rotor) kVA to rated output kW
Over
1
up to
2.5
415 V
10.5
Over
2.5 up to
6.3
415 V
9.8
Over
16
415 V
9.2
up to
40
415 V
8.7
6.3 up to 16
Over Over
40
up to
100
415 V
8.2
Over
100
up to
150
415 V
7.8
Over
150
up to
250
3.3 kV and above
6.0
Over
250
up to
630
3.3 kV and above
5.8
Over
630
up to
1 600
3.3 kV and above
5.6
Over
1 600
up to
4 000
3.3 kV and above
5.4
Oser
4 000
up to 10 000
3.3 kV and above
5.2
3.3 kV and above
5.0
Above 10 000
Notes:
(1) To obtain the ratio of starting (locked rotor) current to full load current, multiply the above ratio by per unit efficiency and power factor at rated load. (2)
Depending on the efficiencies and power factors involved, the above values correspond to: 6 to 7 times full load current for 415 V motors 5 to 6 times full load current for 3.3 kV and above.
(3) 624
The above values are selected from BS4999, Par( 41.
Types and performance of motors A variety of designs may be used to obtain required characteristics in this way. These include , types of cage rotors: folio% ■ in[i. pes — rectangular or round section rotor [
•
[ , .[[- s• ,;:r
•
at displacement types — d eep rectangular bars, [-section bars.
[-[,,lor rotors. resistance rotors.
• .i ure
7'.1 illustrates all five types of rotor and gives
toruue-speecl curves. i[h the current displacement type, the rotor current cd towards the top of the bars at starting, due r tkely high value of reactance at the bottom .i i [. r ,l a ,c ;He lots. This results in an effective AC resistance E1,[derablv higher than that experienced when the is running at full speed, with the rotor bars .eraring at very low slip frequency. There is thus an ' i ,,, , r eased ratio of starting torque to starting current, ...,, mpared with the normal type of cage winding. The action of the double-cage rotor is similar, in Ei :he rotor current is forced into the high resistance .• ier-cage winding at start due to the higher reactance Hie inner cage. The major component of starting ., , rque is thereby produced in the higher resistance When the motor is up to speed, the reactance the inner cage winding is relatively low due to the alue of slip frequency and the bulk of the current IONS land hence torque) is produced in the low resistance !:lier-cage winding. The trislot rotor is another varia'E on in which a high resistance outer-cage produces bulk of the starting torque. The running winding of two rows of inner slots containing the in.1.1ted inner winding, which consists of short circuited :arris forming closed loops spanning approximately a pole pitch. This type has an even better ratio of :ariing torque to starting current than the double.:: 02 rotor, but both double-cage and trislot rotor machines have a high starting torque (see Fig 7.1). All He above types of cage winding have been used for p. o+%er station applications, the choice depending on power output and speed of the motor, the appli-aion and performance characteristics required. For Tol1 drives, such as boiler feed pumps and draught plant, the performance available from normal cage or ..arreric displacement cage designs is perfectly suitable. poable-cage and trislot type rotors are generally not .1,- mechanically robust as the other types and may !hca efore be restricted in power output or speed (e.g., > ) \I\V at 1500 r/min and below and 2 MW at rimin or above). Double-cage and trislot rotors [crid to be restricted to drives requiring a high starting :orque, e.g., pulveriser mills. The high resistance type cowl- is constructed of high resistance rotor bar masuch as bronze or other .high resistance alloy. -
,
C = DOUBLE CAGE D = TR1SLOT ROTOR E = I-HGH RESISTANCE CAGE
ble-.2.ige rotors.
• l) •
A = NORMAL CAGE B = DEEP BAR. 8 2 = L BAR. 8 3 = T BAR
FIG. 7.1 Torque-speed curves of cage induction motors
The high value of resistance gives a high value of starting torque but also results in a low operating efficiency due to increased rotor 1 2 R losses. This type is therefore mainly used for applications where a high starting torque is required but operating efficiency is not important. Because this type of motor has a high slip at full load, its speed can be varied by adjusting the value of supply voltage. Since the high resistance type rotor is an inefficient variable-speed drive it is li mited to drives with intermittent use, such as cranes and actuators, where efficiency is not very important and the higher cost of alternative variable-speed motors is not justified. Figure 7.2 shows the effect of reduced voltage on the torque-speed curve of a typical current-displacement cage-induction motor. It is necessary to ensure that sufficient margin of accelerating torque is available in order to meet the worst conditions, e.g., reduced supply voltage due to rotor starting and high loads such as opening control valves on pumps.
2.2 Slipring induction motors This motor differs from the cage induction motor described in the previous section in that both the stator and rotor are wound with insulated windings, the rotor winding being brought out to sliprings which are connected to external resistances during starting and for speed control. 625
Motors
20
Chapter 7
MOTOR TORQUE at v
2
100 ,JOLTS A 80% VOLTS .0 •
ACCELERATING' .#0 TORQUE it 00 LOAD TORQUE Ot (SPEED)
2
05 SPEED p.u. Fic. 7.2 Torque-speed curves of cage induction motor at reduced voltage
The main application on modern power stations has been for variable-speed drives for starting and standby boiler feed pumps, where its low operating efficiency has not been a disadvantage, due to the relatively low running hours per annum, and the capital cost has been relatively low compared to other variable-speed drives. However, the tendency is now to use direct-on-line cage induction motors driving through variable-speed hydraulic couplings (see Section 5.1 of this chapter). The starting current is much lower than for cage induction motors, a typical value being 120 07o fullload current with 100 07o starting torque. The combined starter and speed controller for these large feed pump motors is of the liquid type. The slip energy to be dissipated in the controller at reduced speed is considerable and the liquid controller is therefore invariably water-cooled in order to dissipate this energy. Methods for recovering this slip energy are available, such as the Kramer scheme where the low frequency slip power from the rotor is converted by an inverter to 50 Hz and recovered by feeding it back to the power supply. However, this scheme is generally only economic for drives with high load factors because it has the disadvantage of a high wear rate on brushes and sliprings which results in a heavy maintenance burden. This scheme has not been used much by the CEGB, although it has found favour with several Western European supply companies. One or two examples do however exist in CEGB, including the boiler feed pumps at West Thurrock power station.
2.3 AC commutator motors The most commonly used variable-speed AC commutator motor has been the stator-fed type, in which both the stator and armature are insulated windings, the armature winding being brought out to a commutator. 626
A typical diagram of connections for a stator-fed shunt-connected motor (which is more often used than the series connection), is shown in Fig 7.3. The action of the commutator is to convert the slip frequency generated in the armature windings back to supply frequency (i.e., normally 50 Hz) across the brushes. The brushes are connected to the main pow er supply through an induction regulator which provides the link between the 'variable 'voltage at the commu_ tator brushes and the constant %..oltage supply. This regulator is then used to inject a voltage into the armature winding via the brushes and causes the speed to be varied in relation to the injected voltage. A t speeds below synchronous, power is drawn from zhe armature and returned to the supply; at super-synchronous speeds power is drawn from the supply and fed into the armature. Further infomation on commutator motors and induction regulators is given by Adkins and Gibbs, 1951 [4j. One of the main applications has in the past been on exhauster fans associated with pulveriser mills on boiler plant, where the variable-speed feature has been used to control the boiler fuel/air flow. The commutator and brushes associated with this type are an obvious disadvantage representing a considerable maintenance task.
2.4 Variable-speed AC converter drives With an increased emphasis now being placed on energy saving methods, coupled with the need to reduce overall costs, increasing attention has been given to
INDUCTION REGULATOR
FIG. 7.3 Stator-fed AC variable-speed commutator motor
Types and performance of motors proci.1 means of providing variable-speed for power uu.siliary drives as a means of saving power. i d on .cent rapid deirelopment of AC variable-speed rhe h.is r now reached a stage where the improved and reliability should result in riub01 H applicaf ion of such drives for controlling ;•1,v, or speed. Variable-speed using DC much used in the old days, but fell out H I' power requirements (see the ncreased i f. ou r li r! chapter). However, with the imo' this Techniques and increase in power ratings of recent years, the use of AC variablerter drives is increasing and is competing 1 of her methods of controlling speed or flow, such : 1 ne or damper control of fans or control valves for ! fhe following types of drive are discussed as follows: • •
motor, with slip energy recovery.
• \olL1C ource converter. • arrent source converter. • Piii,e-Ni. dth-modulated (PWM) converter. oltage source inverter, the current source inverter he pulse-width-modulated converter can all be ,: ‘ itieLl as DC-link converters because the AC supply re,:ified to DC before it is filtered and fed into the • crier, in which thyristors or transistors are switched , lientially to generate a variable-frequency supply to motor. 2.4.1 Cycloconverter ..-.,:l morp,erter converts the mains frequency into • ...friable frequency directly through a one-step con.T , ion process. This is the essential difference from i%pes of converter described later, where the line first converted to DC and then to variablethrough an inverter. A cycloconverter can be to generate variable-frequency variableto drke an induction motor. It can also be used he rotor circuit of a slipring motor for slip-energy as described below. The output frequency is to approximately 40 070 of its input frequency to an acceptable waveform. The cost and cornof power and control circuits make them uniretitke with other types of converter drives for .tt,:ral applications. However, they have been used for . •• .nertt mill and steel mill applications, where the mills re directly coupled to the motor which is supplied by .ii\% frequency cycloconverter. The cycloconverter has •Li tar been used in CEGB power stations. 2 4.2 Slip-energy recovery systems -
',
i' - flergy recovery systems, in conjunction with a ..locorkerter or one of the DC-link type converters
and a slipring induction motor have been used, particularly in Western Europe, for boiler feed pump drives. However, a major disadvantage is the current collection associated with the slipring motor which adversely affects reliability and increases maintenance. The use of cage induction motors up to the limit of forced commutation (about 1.5 MW) in conjunction with one of the DC-link type converters, and brushless synchronous motors above this 1eel (up to about 20 MW), avoids these problems. All static converters inject harmonics into the power supply system, the amount of which is significantly affected by the type of arrangement used for the rectifier. This arrangement also significantly affects the power factor. The harmonic levels must be acceptable to the power supply system and other connected plant. All types of converter also inject harmonics into the motor, the extent of which depends on the type and design of converter and also the motor leakage reactance. One effect of this is to increase the motor losses. 2.4.3 Voltage source converter
A voltage source converter feeding an induction motor is shown schematically in Fig 7,4. The required output voltage is achieved by controlling the rectifier and the required frequency by controlling the switching of the inverter thyristors. Auxiliary forced-commutation circuits are required to turn off each inverter thyristor at the end of its conduction period, but these circuits are not described in detail here. Voltage source converters can be used with standard induction motors, although some derating may be necessary due to the effects of harmonics, as mentioned above. An example of the application of a voltage source converter is to be found on the gas circulator drives for AGR nuclear reactors, to provide low speed barring and also a variable-speed facility for reactor depressurised conditions. 2.4.4 Current source converter
A current source converter feeding an induction motor is shown schematically in Fig 7.5. The DC current is controlled by employing a current regulation loop, which in turn controls the voltage from the phasecontrolled rectifier. The thyristors or transistors of the VARIABLE VOLTAGE DC. LINK
C
CONTROLLED RECTIFIER
FIG.
IN
7.4 Voltage source converter
627
Motors
Chapter 7
VARIABLE VOLTAGE C LINK
AC
CONTROLLED RECTHE-
INVERTER
7.5 Current source converter
inverter steer the current source into the three phases of the motor winding to generate a variable-frequency six-stepped current wave. Because of the large DC link reactor and the controlled-current mode of operation, the converter is inherently rugged and has an ability to recover from malfunction. Since the motor is part of the commutating circuit and commutation depends on the motor subtransient reactance, the converter needs to be matched electrically to the motor. The sudden changes in current which are inherent in the output current waveform result in large transient voltage spikes at the motor terminals 2.4.5 Pulse-width-modulated converter
A pulse-width-modulated converter feeding an induction motor is shown in Fig 7.6. A diode rectifier with a small filter capacitor generates a constant DC link voltage: both the magnitude and frequency of the output voltage are controlled within the inverter. The inverter typically has a similar circuit configuration to that of a six-step voltage source inverter, but has a much more complex switching sequence: in addition, there is usually an auxiliary commutating thyristor associated with each main thyristor. Microprocessors are now being introduced into the control circuits. Rapid thyristor or transistor switching is required, so that each half of the output voltage waveform consists of a number of pulses of equal amplitude. The magnitude of the fundamental output voltage is controlled by variation of the total voltage-time area for a half cycle. By suitably modulating the pulse width, the harmonic content of the output voltage can be reduced to a low level. For synchronous motors, the inverter is commutated by the motor voltage, which is known as 'machine
CONSTANT VOLTAGE D.C. LINK AC
—110DIODE RECTIFIER
FIG. 7.6 628
INVERTER
Pulse-width-modulated converter
commutated', and the relatively expensive forcedmutation equipment necessary for induction m rtotilr; can be eliminated. However, forced commutation has to be provided during the initial starting period, up t o approximately 10N speed, because the voltage obtained from the motor during this period is too low to corn. mutate the inverter. Machine-commutated converters for synchronous machine drives are well established and their previous uses include starting schemes for large hydro-generators, e.g., Dinorwig power station, gas-turbine sets and synchronous compensators at some transmission sub-stations. They have additional merits when used with brushless excitation arrangements on the motor and have been used by some Western European supply companies for variable-speed boiler feed pump and fan drives. The advantages of variable-speed AC converter drives can be summarised as follows: • High efficiency, which is maintained at reduced powers and speeds. • Wide speed range (10:1 readily achievable), \kith accurate speed control (1 07o). • Low starting current (i.e., 1 to 1.5 x full-load current (FLC), compared with 5 to 7 x FLC on cage induction motors) with possible cost savings on the power system due to lower starting current and also to less arduous starting conditions for the motor. • Regenerative braking can be provided, if necessary. • Converter equipment can be continuously monitored thus facilitating identification of any faulty equipment or components. • Reduce space required local to driven equipment, compared with cage induction motors driving through hydraulic couplings. • Maximum speed is not limited by power system supply frequency, for example, speeds greater than 3000 r/min on 50 Hz supply are possible. • Relatively easy to convert existing fixed-speed drives or to replace obsolete variable-speed drives. Examples have occurred during refit programmes of fossilfuel power stations.
2.5 DC motors The main application of DC motors in modern power stations is for standby auxiliaries associated with vital services, such as the lubricating oil system of the turbine-generator unit. Thus, if the AC supply to the station auxiliary system fails completely, the turbinegenerator bearings can be fed by the DC motor-driven lubricating oil pump powered from the station bat tery. On older power stations, DC motors were often used for variable-speed drives, such as boiler fans, etc. However, with increasing power requirements, which tended to exceed the capacity of commercially available motors, together with the need to improve reliability
Design and construction maintenance, this type is now seldom used ch applications and has been largel y superseded for ili ,. ,if i a ble-speed AC motors, where such speed control required (see Section 2.4 of this chapter).
vides the location for the stator and rotor assemblies, cooler and bearings. The base has to withstand torsional loads, bending forces in both axes and the weight of the motor. The principal CEGB requirements are:
and construction 3 Design
• Motor frames, end shields, external end covers, external fan cowls to be constructed of metal and be robust enough to withstand conditions experienced within the power station such as ‘ibration, impact and environmental.
cc:duce
3 1 Mechanical construction p, c onstruction of motors depends on many factors
the manufacturer, type, motor rating and, of the application. For small motors, the use of ,iluminium is increasing for stator frames, cage rotor ,,i„dirws and even stator winding conductors. For and large motors, the stator frames are mostly :1 dium rabrieated-steel box construction, although cast iron sc.mnetimes used for medium sizes. ioure 7.7 illustrates the sectional arrangement of a puJal medium-size horizontal cage-induction motor. Hie hase is the main constructional member and proas
• Glass fibre and plastic components must be of adequate design and robustness to withstand the long term effects of the environmental and operating conditions. • Duplicate motors and their major components to be interchangeable. • Motors, including those with pedestal-type bearings, to be designed so they can be moved as an integral unit.
•
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FIG. 7.7 Sectional arrangement of cage induction motor
629
Motors
Chapter 7
The construction of stator and rotor cores varies from one manufacturer to another and is also a function of type, size and speed. A common method of construction of stator cores of medium and large motors is to build the laminations on mandrels. The laminations are then N.yelded to a framework to form a stator pack. For rotors running at high speed and for those of large diameter, it may be necessary to shrink the laminations onto the shaft or .shaft spider. The radial airRap between stator and rotor cores must be of sufficient length to prevent the possibility of rubbing between stator and rotor cores during all conditions of service. This must take into consideration the effects of any shaft deflection due to unbalanced magnetic pull. This conflicts with the need to keep the radial airgap small in order to minimise the magnetising current to obtain an improved electrical performance, particularly power factor, of low speed motors.
3.2 Types of enclosure The motor enclosure is chosen to give adequate protection to persons against contact with live or moving parts inside the enclosure and to the machine against the ingress of solid foreign bodies. Adequate protection is also required against the harmful ingress of water and other liquids. The most vulnerable part of an electric motor to contamination is the electrical insulation of the windings and electrical terminations and it is important that the correct choice of enclosure is made in order to ensure good reliability. The ingress of coal dust, cement dust, water, steam, oil or other contaminants could cause premature electrical or mechanical failure, or overheating of the motor due to restriction of ventilation circuits.
A primary consideration when choosing an enclosure is to examine the environment and decide whether it is suitably clean and dry for direct cooling, using a ventilated type of machine, or whether there is any risk from airborne dust, water, steam, oil or saline atmosphere, which will require total enclosure of the motor. A significant factor in this choice is capit a l cost, which is usually higher with totally-enclosed type s. Other factors which can influence the choice of e n _ closure are whether the motor is situated indoors, or is outdoors and exposed to the weather. Saline environments, such as those encountered with coastal power stations, are particularly arduous. Site conditions during the construction and commissioning of the power station have also to be taken into account, since the risk is greater, often for long periods of time. A list of standard machine enclosure types used in CEGB power stations is given in Table 7.2. The general trend is for the greater use of totally. enclosed type motors and they are invariably used for boiler auxiliaries, due to higher levels of contamination. There is also an increasing tendency to use them on turbine-generator auxiliaries, in view of the risk of contamination from steam, water or oil, or from activation of fire protection equipment. With small power motors up to approximately 10 kW, the technical and economic advantages of ventilated-type motors are so marginal that totally enclosed motors are invariably used. For outdoor applications, totally-enclosed weatherproof motors are used with special features provided, such as bearing seals, gaskets between flanged joints and protective finish to bare metal surfaces, such as shaft extensions, etc. Pipe- or duct-ventilated motors have occasionally been used in special applications, such as circulating water pumps. These have advantages, particularly for larger machines, where a source of clean air is readily available (inlet duct), or where the
TABLE
7.2
Typical motor protective enclosures and methods of cooling
Protective enclosure BS4999, Part 20. (IEC34-5)
Description
Method of cooling BS4999, Part 21. (1EC34-6)
IP 22
IC 01
Totally-enclosed, fan-ventilated
*
IP 54
IC 01 41
Totally-enclosed, closed-air-circuit, air cooled, integral heat exchanger
*
IP 54
IC 01 51
Totally-enclosed, closed-air-circuit, air cooled, machine-mounted heat exchanger
*
IP 54
IC 01 61
Totally-enclosed, closed-air-circuit, water cooled, machine-mounted heat exchanger
*
IP 54
IC W37 A81
Totally-enclosed, closed-air-circuit, water cooled, separately-mounted heat exchanger
*
IF 54
IC W37 A91
Drip-proof, screen protected
* Motors which are situated outdoors or exposed to the weather are required to have a weather-protected enclosure, IPW 55.
630
Design and construction diccharge of relatively large quantities of hot air could affect the ambient temperature to the detriment of ating staff or other plant (outlet duct). However, r he more usual types of enclosure for circulating water t romp motors are drip-proof screen-protected or totallyxclosed, c losed-air-circuit, air cooled with an increasy towards the latter, particularly for coastal w , Rrn d eri sr:Itions due to the risk of saline contamination. The twe of enclosure is defined in BS4999, Part 20 [Ec- 34-5) and contains an international code, consis[in. of the letters IP followed by two numerals. The it (0 to 5) signifies the degree of protection fii„ / di g ,ainst contact by persons with live or moving parts j iiiside the enclosure and of machines against ingress of solid foreign bodies. The second digit (0 to 8) signifies the degree of protection against harmful ingress of water. In general, the higher the number, the higher is he degree of protection. Table 7.3 lists some typical motor auxiliary drives for a CEGB power station and ‘.es the types of enclosure used.
3.3 Methods of cooling With the ventilated types of enclosure, the smaller ,ites of motor are normally provided with axial-type ,entilation, which comprises a single radial fan drawing air through axial ducts in the stator and rotor cores (iron laminations), and over the endwindings: it is then discharged to atmosphere. For larger machines, the cooling surface is increased by using a combination of axial and radial ducts in the core. The largest machines usually have radial-type ventilation with two
parallel air circuits: shaft-mounted fans at each end of the rotor circulate cooling air towards the centre of the rotor and radially outwards through ducts in the rotor and stator cores. Figure 7.8 shows a section through a typical radially-ventilated drip-proof motor. With totally-enclosed machines, the variations in overall designs are greater but the arrangements of cooling air flow within the machine are basically similar, except that they are arranged for a closed circuit. At the small power end of the range, the totallyenclosed motor depends on free convection at its outer surfaces with or without an internal fan. For larger motors, both internal and external fans are provided, with heat transfer taking place through fins provided on the stator frame. This is the well known totallyenclosed fan-ventilated motor. Rigger motors have heat exchangers built into the stator frame, or more often are provided with an integral air-to-air heat exchanger unit mounted either on the machine or, for the largest machines, separately mounted. Figure 7.9 shows a section through a typical closed-air-circuit air cooled motor with radial ventilation. An alternative to the air-to-air heat exchanger is the air-to-water type, where water passes through parallel rows of cooling tubes and the motor primary cooling air flows over the tubes. The outsides of the tubes are usually finned to increase the surface area. Figure 7.10 shows a section through a typical closed-air-circuit water cooled motor with radial-type ventilation. For enclosed type motors rated up to approximately 1500 kW the use of water cooling is generally not technically or economically preferred and air cooling
11111111111111111111111
FIG. 7.8 Section of radial ventilated induction motor
631
Motors
Chapter 7 TABLE 73 Some typical motor auxiliary drives (660 AlW turbine-generators)
Auxiliary
Type motor
Power, kW
Speed, r/min
Voltage, V
Enclosure
Number per unit
Mounting
— 1
Turbine-generutor
Sq. cage DC Sq. caee Sq. cage Sq. cage Sq. cage DC
53 19 36 50 11 15 15
1450 1450 9-10 1450 1450 1450 1450
415 250 DC 415 415 415 415 250 DC
TEFC DPSP MEC TEFC TEEC TEFC TEFC
>> zz z
Sq. cage DC
37 37
2930 2930
415 250 DC
TEFC TEFC
II
AC Lub-oil pumps Standby lub-oil Jacking oil punip ,, Turning gear Oil purifier 1-1ydrogen seal oil Standby seal oil Stator m.inding liquid pump: — main — standby
Sq. cage or slipring Sq. cage Sq. cage
9000
1480
II 000
CACW
920 920
990 990
3300 3300
CACA CAC.A
Sq. cage Sq. cage Sq. cage Sq. cage Sq. cage
3200 2200 330 500 2630
590 590 980 1480 1480
11 000 11 000 3300 3300 11 000
CACA CACA CACA CACA CACA
Sq. cage
3500
980
11 000
DPSP
Sq. cage
5000
2980 or 1470
ll 000
Submerged CO 2
Sq. cage
6000
1475
11 000
Special*
2 Feed pumps and feed heating plant
2 x 50ro 3 3
< 50 0-0
11111
2 2
< .5 0
>
I I>
Starting/standby Feed pumps Feed suction pump Condenser extraction pump
4:station
3 Coat-fired boiler I D fans FD fans Pulveriser mills PA fans Sootblower compressor
1
10 10 4, station
4 Circulating water pumps CW pumps 5 Reactor — AOR 8 I>
Gas circulators
8
6 Reactor — P KR Reactor coolant pumps
Abbreviations
TEFC — DPSP I-1
ID FD CACW —
totally-enclosed fan-cooled drip-proof screen protected horizontal vertical induced draught forced draught closed-air-circuit water cooled
is standard practice. For larger motors up to approximately 5000 kW, both air and water cooling are usually available, but air cooling is preferred unless there is substantial justification for selecting the water cooled type, e.g., overall cost, ambient temperature, etc., since air cooled motors are self-contained and not reliant on an external supply of cooling water. For motors above approximately 5000 kW, the physical size of air-to-air heat exchangers becomes large compared to water cooling, due to the poorer heat transfer properties of air, and for machines of this size water cooling is usually preferred for cost and physical size considerations. Where water cooling is employed, the coolers are mounted at the side or underneath the motor if p05632
CACA PA CW Sq.cage AGR PW R
— — — —
4
closed-air-circuit air cooled primary air circulating water squirrel cage induction advanced gas cooled reactor pressurised water reactor located inside reactor containment
sible in order to minimise the possibility of water contaminating the windings in the event of a leakage. If the cooler is mounted above the motor, spray baffles should be fitted to deflect any leaking water spray away from the windings and towards the bottom of the machine where an alarm should be provided. Catchment trays should also be provided under the cooler stack to contain any leaked water. At coastal power stations, the use of sea water for direct cooling of motors is avoided to eliminate the risk of corrosion and fouling of cooler tubes, towns main water being always used. The method of cooling is defined in B54999, Part
21 (IEC 34-6) which contains an international code consisting of the letters IC, a group of one letter and
Design and construction
N
I I
l
1
,
I
I
A 1
I A
__I
/ / / /
FIG. 7.9 Section of closed-air-circuit air cooled motor
(5-6 C
a
a55 5
5
-5
6
a 5
5 0 0 a 5
a
a
5
-0
,1
r■•■■1.
FtG. 7.10 Section of closed-air-circuit water cooled motor
i■■
0 numerals for each coolant circuit. The letter nifies the nature of the coolant (e.g., A — air, W %1. ater), the first numeral (0-9) the means of cirmiating the coolant and the second numeral (0-9) the method of supplying the power necessary to circulate
,
the coolant. Where there is a primary and secondary coolant circuit, the secondary is stated first, e.g., IC W37 A91 (closed-air-circuit water cooled, with machine-mounted cooler). Examples of types commonly used by the CEGB are given in Table 7.2. 633
Motors
Chapter 7
Separate motor-driven cooling fans are occasionally used for very low-speed motors or for variable-speed motors having a wide speed range. Examples are variable-speed AC commutator motors on older power stations for boiler fan drives.
3.4
Windings
Stator windings normally used by the CEGB are: • Random wound (Mush) Single- or two-layer lap 415 V winding, with circular conductors. Considered unsuitable for use on voltages )3.3 kV. • Diamond windings Two-layer lap winding, 3.3 kV and above with coils pre-formed and insulated prior to winding. Open-type slots. Used on voltages )33 kV. Note:
for the largest motors, half coils may be used, with turn-toturn joints made during the winding process. • Hairpin (concentric) — Single-layer winding. windings — Slot portion and closed end of winding preformed 3.3 kV and above and insulated. .Open end of winding has to be formed and individual turn-to-turn conductor joints made during the winding process. Semi-closed slots are normally used.
Note: This has now been largely superseded by the diamond winding, due to cost, ease of repair and high load-losses. The stator winding and its insulation system is one of the most critical areas of the design. This needs to be of high reliability, of established and proven design, and able to meet the combined effects of: • Electrical/dielectric stresses. • Thermal endurance. • Thermo-cycling. • Mechanical and thermal stresses. • Contamination. 634
• Environmental conditions. Power station motors are required to have a life endurance of at least 18 000 starts. Stator windings must be adequately supported, braced and blocked to provide sufficient rigidity during all conditions of service. Special attention needs to be given to the support and bracing system of the stator endwindings of cage induction motors which are t o be direct-on-line started, to cope with the meehani_ cal and thermal stresses produced by the high starting current. The support system for windings of vertical motors must prevent any downward displacement occurring in service. Magnetic slot wedges are generally not so reliable as the non-magnetic type, in that they are liable to delaminate and loosen, so their use is therefore avoided where possible. The electrical joints and connections must withstand the mechanical and thermal stresses involved and should be of brazed or welded construction. Wound rotors for slipring, Ac commutator and DC motors are normally wound two. layer lap or wave, depending on the voltage and current involved. Similar considerations apply as for stator windings, but additionally the windings must be designed to withstand the rotational stresses. The windings are connected to sliprings or commutators. Cage windings must also be designed to withstand the thermal and mechanical stresses during starting, which can be high, particularly on high inertia drives such as boiler induced- and forced-draught fan drives. Rotor bars must fit tightly in their slots to minimise bar vibration in a radial direction, which could cause premature bar failure. The cage short-circuiting endrings should be of jointless construction in order to avoid the risk of joint failure.
3.5 Insulation systems The classification of insulation systems is given in BS2757. Insulated windings are Class B or F. Class H is generally only used for applications involving high ambient temperatures such as sootblower motors. Insulation systems must be of proven design and reliability: for voltages of )3.3 kV, they are required by the CEGB to be type-tested. Further discussion on the performance and test methods of high voltage AC motor insulation is discussed by Schwarz 1969 [5]. The CEGB testing requirements for insulation systems of motors of )3.3 kV are given in ESI 44-5. A summary of these tests follows.
Type tests Intended to evaluate the basic design, materials and manufacturing process of the insulation system. They involve testing at least two sample coils. The tests include: • Dielectric loss tangent/voltage characteristic of slot cell insulation and its stability during one thermal cycle of 140 ° C )5 kV.
Design and construction
• •
Inter-turn insulation I min, 50 Hz withstand voltage, instantaneous 50 Hz withstand voltage.
also
Slot cell and endwinding insulation 1 min, 50 Hz ithstand voltage, also instantaneous 50 Hz withand
Ilat.2 e. quaiity control tests durin2 manufacture in-
•
DIelectric foss tangent/ voltage characteristics at temperature ?..5 kV. Test requirements depend r00'1 on the type of insulation system, i.e., resin-rich or \-acuum/pressure impregnated (VP F), and also on voltage, polarity and kW output of motor.
a high frequency impulse • I n ter-turn insulation — ,oltage is injected to the leads of each coil, the peak voltage being U peak = 3 U il sh/s/3, where U, Is he rated line-to-line voltage. • Complete winding — I min, 50 Hz overvoltage test to BS4999, Part 60. The insulation systems of stator windings are specified
he of the epoxy type, with thermosetting materials, i N,sith the main slot cell insulation based essentially mica. The conductor and enclwinding insulation of \sindings ?..6.6 kV should also be based on mica. The anis adjacent to the ends of the slots on such windings Jr,: treated to provide electric stress control, usually hv a semi-conductive tape or semi-conductive varnish. The slot portions of the coils are treated to prevent corona discharge, usually by means of an outer layer of conducting tape. The windings must be impregnated and suitably pro• to seal them effectively to prevent deterioration Cron] adverse environmental conditions at site. Two ,Ii•ulation systems are in general use for windings at !3,3 kV: ,
0
mil oil
• The resin-rich system Coils are insulated with tapes heasily loaded with uncured resin, usually referred to as B-stage resin. The coils are then cured by heatinu and pressing individually in moulds, or someti mes (for smaller machines) after winding into the stator core. Figure 7.11 shows details of an II kV diamond-type coil, including slot configuration. • Vacuum/pressure impregnation (VPI) The stator is wound with coils, which are insulated with dry semiporous tapes: the winding is then vacuum dried, Impregnated under pressure and cured by heating. Ihe resin-rich system has been used in the UK for many years, but is tending to be superseded by the Pl system which has been extensively used in the LS- and other countries for several years, with much 'th:CeSS. This is mainly due to the better quality control possible during manufacture and the achievement of %old-free windings.
SECTION SHOWING TYPICAL SLOT CONFIGURATION 2 TURN COIL. 2 CONO TURN
Fro. 7.11 II kV diamond-type coil
3.6 Bearings Bearings can broadly be divided into two main types: rolling element bearings (sometimes referred to as frictionless bearings) and plain bearings. These can take various forms, depending on the rated power and speed, whether the shaft is vertical or horizontal, and also on the radial and axial loadings. Rolling bearings take the form of balls, cylindrical
rollers, tapered or spherical rollers. They depend for their satisfactory operation on the clearance between the rolling elements and their races, sometimes referred to as the diametral bearing clearance. Grease is gen635
Motors
Chapter 7
orally used as a lubricant, but for certain designs or applications oil is occasionally used. Lithium-based creases have replaced soda-based greases for power station motors, due to their stability at higher ternperatures and improved lubricating properties. The construction of the bearing assembly should be such that the bearings can be dismantled without risk of damage. Split-type roller bearings have been used to 'acil tote maintenance on some large motors, e.g., circulating water pumps. Precautions need [ 0 be taken against the effects of any vibration which could be transmitted when the motor is not running, for example, standby motors. Pre-loaded ball bearings are often used for these applications. Alternatively, plain bearings are used, since these are inherently less prone to damage from such effects. Figure 7.12 shows a typical arrangement of a crease lubricated rolling bearing. Within the size range in which they are used (see Table 7.4), rolling bearings have the following advantages: • Low cost. • Replacement bearings usually readily available. • Grease lubricant gives good protection against ingress of moisture and dirt into motor. • Easier to seal against leakage of grease into motor, as compared with oil. • Low friction torque at starting. The larger power motors use plain bearings, which may be of the sleeve or tilting-pad type. Oil lubricated bearings may be self-lubricated by means of oil rings, or by a disc running in an oil reservoir. Where forcedoil lubrication is required (for example, in the case of high speeds of 3000 r/min or high bearing loads), the oil pump is driven from the main shaft system and is self-priming. Where possible, such a lubricating system is made common to the motor and its driven auxiliary. Tilling-pad bearings are used where appreciable axial thrusts are present, for example, in vertical motors for circulating water pumps. Lubrication must be adequate during starting, particularly of standby equipment with automatic start, and also during running-down if this
TABLE •.4 Fin. 7.12 Typical arrangement of a grease lubricated rolling-type bearing
Type of motor bearing
Synchronous speed — rim n
636
Rating
Type of bearing
1000 and below
Up to 750 kW
Rolling
1000 and below
Above 750 kW
Plain
Above 1000, up to 1500
Up to 530 kW
Rolling
Above 1000, up to 1500
Above 530 kW
Plain
Above 1500
Up to 375 kW
Rolling
Above 1500
Above 37$ kW
Plain
is of long duration, such as can occur on high-inertia loads. A motor-driven oil pump may additionally be fitted in such cases. A motor-driven jacking oil pumP may be needed for starting drives with heavy shaft loads. Figure 7.13 shows a typical arrangement of an oil lubricated sleeve-type bearing. For motors above 750 kW, it is the practice for bearings of the motor and its driven auxiliary to be
Technical requirements power stations, the electrical auxiliary system to which the motors are connected is subject to high fault levels, so the effects of an electrical fault must be taken into account in the design of the terminal arrangement and terminal box to prevent a possible explosion due to the rapid heating of gas in a confined space with risk of injury to personnel or damage to plant (see Schwarz 1962 [61). The CEGB requirements are summarised as follows: •
Minimum electrical clearance and creepage distances are specified.
• Terminal boxes must be suitable for the type and size of cable to be used. • Terminal boxes for 415 V motors up to 75 kW shall be totally enclosed (IP 54) but may be open to the interior of the motor. Above 75 kW, the terminal boxes must be constructed of steel, be totally enclosed (IP 57) and sealed from the motor interior. • For 3.3 kV motors, a standard terminal box has been developed in conjunction with manufacturers. This is totally-enclosed (EP 57), phase-insulated, and of the pressure-relief type, with fully-insulated terminals. Maximum fault capacity 250 MVA. Maximum current rating 290 A. For use with threecore, plastic-insulated cables up to 300 mm 2 , solid aluminium or copper conductor. Figure 7.14 shovis details of this terminal box.
7
.13 Typical arrangement of an oil lubricated
sleeve-type bearing
H We same type in order to ensure that incorrect
di , :ribution of bearing loads does not occur due to differences in shaft lift during run-up, or of different idtcs of bearing wear, ProN.ision must be made for the prevention of idin3ge to bearings by any shaft currents which may kc produced by uneven fluxes in the magnetic circuit H the motor. This is achieved by insulating the !' ,:arintls, if shaft currents are likely to occur. fable 7.4 gives details of the CEGB practice for l'cahnL, applications.
3.7 Terminal boxes Particular attention has to be given to the design of the :Lirininal arrangements and of terminal boxes in order lo achieve a high degree of reliability and also to facilate installation of the power supply cables. Within
• For 11 kV motors, a standard terminal box has been developed in conjunction with manufacturers. This is totally-enclosed (IP57), phase-segregated, and of the pressure-relief type, with fully-insulated terminals. Maximum fault capacity 750 MVA. Maximum current rating 650 A. For use with three singlecore, polymeric-insulated cables up to 500 mm 2 , with moulded elbow-type connector. Figure 7.15 shows details of this terminal box. • Terminal boxes for ?-3.3 kV to be type-tested to withstand internal short-circuit and through-fault current capability.
4 Technical requirements Some of the principal requirements of CEGB power station motors are given below. EEC documents equivalent to BS are also given. Relevant standards: BS5000, Part 40 BS4999, Parts 10, 20, 21, 30, 32, 33, 41, 50, 51, 60 (IEC 34, Parts 1, 2 and 4 to 10). ESI Standards 44-3, 44-4, 44-5. Service conditions: Ambient air 40 ° C (max) Cooling water 30 ° C (max) (normal) 637
0)
co
GLASS POLYESTER TERMINAL BASE
TERMINAL BOX
LID
MOTOR CONNECTING FLEXIBLE CABLE
EARTHED STEEL FLASHPLATE
111 PRESSURE RELIEF DIAPHRAGM
NEOPRENE RUBBER CAP
PROTECTIVE MESH GRID
0
A
■
4
0
0
0
0
(
CABLE SPACING BLOCK
t
0
0
I I
o
_1_1=1_1___
\
\ \
\
I
/
/
\
\
\
I \
j
\
\.\
\
V
/
/
/
0
I
0
/
/
I
I
/
/
/
o
// /
\ 3 CORE
POWER SUPPLY 'CABLE
I I
I 7 I
I
1,) _ _11
Section Through Box
View on Front with Lid Removed Fla- 7.14 3.3 kV ( 1
.
(■ 11/B1.AN1A
l
Jrfl IuI
1)1.
■■
0
CONNECTOR
JOINT ACCESS COVER
TERMINAL BOX// LID
/ JOINT INSULATION
o
p
_
0
0
/, '0-
VOLTAGE TEST POINT
a
0)
BUSHING
n
(
0
) SPADE TERMINAL
o
PROTECTIVE MESH GRID
n
0 0
0
0
PRESSURE RELIEF DIAPHRAGM
0
STRESS RELIEF ADAPTOR
_,.. 1,
A— EARTHED STEEL ARC BARRIER
SINGLE CORE POWER SUPPLY CABLE
Section through Terminal Box
Fiu. 7.15 11 kV CEGI1/131:AMA 14:Emilia] Iro.
Y, e View on Front with Lid Removed
' .,.,• 0
sluat.ua.i!nbai leD)ukpai
MOTOR CONNECTING FLEXIBLE CABLE
VOLTAGE TES i POINT cap
Motors
Chapter 7
Temperature rises:
To BS4999, Part 32 (IEC 34 — 1), except that temperature rise of Class F insulation to be to limits of Class B.
Rating:
Maximum continuous rating.
Nlinicaurn daring star:ing period:
SO'''n rated voltage
Variation of voltage and frequency:
94% to 106a voltage and 9607o to 102% Hz. Capable of continued operation at 75 0'ii voltage for 5 minutes without injurious heating.
Transient recovery:
To recover after a power supply system disturbance causing loss of voltage for 0.2 seconds, followed by sudden restoration to 60% voltage for 3 seconds, followed by restoration to 80% voltage, and then ultimate recovery to normal.
Starting (lockedrotor) kVA for cage induction motors:
Selected from BS4999, Part 41 (see Table 7.1)
Locked-rotor torque for cage induction motors:
Must be adequate to meet requirements of driven load, but in any event CEGB practice requires the values to be not less than those given in BS4999, Part 41.
Starting (run-up) torque of cage induction motors:
The accelerating torque at any 0 speed and 80 7o voltage must be not less than 10% of motor rated load. The motor starting (run-up) torque at 100% voltage must also be not less than 1.7 times the torque obtained from a load torque which varies as the square of the speed and is equal to 100% torque at full speed.
Maximum (pull-out) 200% full-load torque torque: Noise levels:
640
Uo BS4999, Part 51, except that in no case shall the mean sound pressure level exceed 87dB(A) at 1 metre from the surface of the machine.
Harmonics: (AC converter drives)
Voltage distortion less than with individual harmonic cornponents to IEC 146-2.
Nuclear qualification:
Qualification of Class 1E safetyrelated motors to IEEE 334.
5 Power station auxiliary drives Details of some of the more i mportant motor auriliary drives required on a modern CEGB power station with 660 MW turbine-generator (TG) units are given belmk, and also in Table 7.4.
5.1 Boiler feed pumps The normal arrangement adopted currently by CEGS 0 is for I x 100 70 steam turbine-driven feed pump, with 2 x 50% starting and standby motor-driven sariable. speed feed pumps. Motor-driven suction stage pumps are also required for the feed pumps. Since the motor-driven feed pumps are required for starting and standby duty only, the choice of motor is largely dictated by first cost. Variable-speed sliprinct motors with variable rotor resistance liquid type controllers have been used. Squirrel-cage induction motors with speed control by hydraulic couplings have also been used, particularly for nuclear power stations, where starting is required infrequently. The variable-speed slipring induction motors are typically 1480 r/min (maximum), 9 MW, 11 kV, starting current 100% full load, 50 Hz, with speed variation 100% to 70% by rotor-resistance control, with liquidtype speed controllers. The feed pump is driven through speed-increasing gears at 8000 r/min (maximum). Three x 50% duty suction stage pumps are provided, driven by 1000 kW, 1480 r/min cage induction motors. Figure 7.16 shows a typical slipring induction motor reed pump drive. With the cage induction motor drive, the motors are typically 1480 r/min, 10 MW, 11 kV, 50 MVA at start, 50 Hz, driving through hydraulic couplings with speed variation 100-70%. These are mechanically coupled to the feed pumps via speed-increasing gearboxes at 8000 r/min (maximum) pump speed. The suction stage pump is rated at 1000 kW, 1480 r/min and is coupled to a shaft extension of the main drive motor.
5.2 Coal- and oil-fired boiler units 5.2.1 Draught plant
The practice is to install two induced-draught and two forced-draught fans per boiler unit, each working at full-load when the boiler is at continuous maximum rating (CMR). It is possible to run the boiler unit at reduced load in the event of failure of one of the fans. although it is expected that this condition would nol be allowed to continue for any length of ti me. The
Power station auxiliary drives
STATOR 'WINDINGS COOLING FAN
AIR DUCTS
•
SLiP RING COVER
__ROTOR WINDINGS
-
2_—
Fo O R RHI
• ■ ,I CV AB L
,
r
ipE STAGE
PECESTAL EARTHED THROUGH REMOVABLE O
C o PT HP EE RR WS TI SRE P FULLY INSULATED
DIRECTION OF AIR FLOW
„
L
ING
HEAT EXCHANGER TUBES
L jri_ET
-
-
3 CL c,LLY
PPINGS VENTILATORS BRUSHES
HEAT EXCHANGER COOLING WATER OUTLET
HEAT EXCHANGER COOLING WATER INLET
INSPECTION WINDOWS
FIG. 7.16
• •.
Typical slipring induction-motor feed pump drive
for the motors to be single-speed cage induction although two-speed cage induction and variableiitator-fed AC commutator motors have been i[lie moments of inertia of the fans are high, being ciI ti mes those of their respective motors, which rein relatively long run-up times, typically 50 to 80 s.
5 2.2
Milling plant IIlIlliIlg
plant comprises the coal pulveriser mill,
air Ian (or exhauster fan), coal feeder and , ,ir ,Ar or. Standby capacity is provided. The pulveriser
Luallv
maintenance than any other for this reason, the running , iiiindby units are frequently interchanged. Coal [ Cr wills require a high starting torque (typically i) and a relatively high number of starts per hour CLaJIV six). The vibration level of the plant is also C2]\ high and a robust motor is therefore required. ill enclosed air cooled squirrel-cage motors are proi.ided. ill
need More
the station:
-
5
.3 Nuclear reactors — AGR
5
3. 1 Gas circulators
pical arrangement is for eight gas circulators to
be installed in each reactor to circulate the primary coolant CO2 through the reactor core and boilers. Two basic configurations are in common use in the CEGB, horizontal and vertical; this description concentrates on the vertical configuration, but many of the principles apply to both. Figure 7.17 shows the location of a vertically-opposed gas circulator in a nuclear reactor at Heysham I power station. Each gas circulator is a single-stage centrifugal type, delivering 461 kg/s of CO2 at 41 bar and a temperature of 287 ° C. The inlet gas temperature to the circulator is 278 ° C and the pressure rise across the circulator is 2.83 bar. The circulator is driven at 3000 r/min by an 11 kV motor mounted below the impeller on the circulator shaft (see Fig 7.18). A 415 V pony motor, mounted on the circulator shaft below the main motor, drives the circulator at barring speeds below 350 r/min. The motor unit for each circulator is encapsulated and comprises the composite assembly of main motor, pony motor, rotor shaft, bearings, impeller, inlet guide vanes and isolating dome operating mechanism. This assembly is contained completely within the reactor pressure boundary. The circulator unit can be withdrawn and replaced for maintenance with the reactor depressurised. The impeller shaft passes through a barrier plate which is provided with a labyrinth seal to minimise 641
Mot or s
Chapter 7
LOCATION OF GAS CIRCULATOR Fu. 7.17 Posiiion of gas circulator unit within
AGR reactor
hot gas flow between the motor compartment and the reactor. The impeller operates in reactor gas at nearly 300 ° C, whereas the motor is isolated thermally to operate at temperatures of about 60 ° C. Although normal operation is in CO2 at 41 bar, the circulator must be capable of operation in air at atmospheric pressure (or reduced CO2 pressure) for commissioning, maintenance or during fault conditions. motor
The circulator main drive motor is an 11 kV, two-pole squirrel-cage induction machine contained completely within the reactor pressure boundary. The motor, mounted on the circulator rotor shaft with the 415 V pony motor, rotates at a nominal speed of 3000 r/min and maximum continuous rating of 5.59 MW. The motor is designed to I3S2613 Class F insulation, but operates normally within Class B temperature li mits, The motor is capable of operating continuously, at rated torque, at any frequency between 48 and 51 Hz and at any voltage between ±5% of the nominal value. The motors are designated for 'essential duty' and are capable of continuous operation at 75% nominal volts at 50 Hz for a period of 5 minutes without injurious heating. They are also capable of recovering normal operation in the event of a system disturbance 642
causing temporary loss of supply voltage for periods of up to three seconds, followed by a sudden restoration initially to 80% nominal voltage. The motor stator windings and laminations are con. tam ed within the main motor outer frame which is a mild steel cylindrical ribbed fabrication with top and bottom flanges (see Fig 7.19). The top flange aligns with the lower face of the top bearing bath and the bottom flange aligns with the bottom bearing batch assembly and incorporates holes for the t welve motor securing bolts. The stator and outer frame complete weicth s approximately 14.5 tonnes. The rotor is fitted on the forged carbon steel shaft together with the impeller, drive-end bearing sleeve, motor cooling fan, pony motor rotor, non-reverse clutch, pulsing disc and non-drive end thrust collar (see Fig 7.20). Intensive research, development and full-scale t!stin g were required to establish the design of these ors, which have to operate under arduous conditio . The motor has also to withstand specified radiatio•: levels and also operate with contamination from lubricating oil mist. All these presented problems; in particular, the design of bearings under high rates of change of pressure of the ambient gas, the insulation system, the electrical design and thermal design. These are discussed in more detail (see Schwarz 1973 l7j). A very high reliability is required, particular' . since the units are inside the reactor pressure cm 'ent and even apart from safety aspects, any 1: led outage can be very costly.
5.4 Nuclear reactors — PWR 5.4.1 Reactor coolant pumps
A typical arrangement is four reactor cook: •)nper reactor which are located within the re:. :.e• tainment. The pump unit consists of a vert:. .tor stage centrifugal-type pump, with vertical dr. mounted above the pump and directly coupled to it. The motor has a drip-proof enclosure, but the cooling air outlet is water cooled. A flywheel is located at the top of the motor to provide the required coastdown capability in the event of loss of electrical power supply to the motor. This limits the transient temperatures within the reactor under such conditions. The motor must withstand specified radiation levels within the containment. Figure 7.21 is a cutaway view of a typical reactor coolant pump and motor unit. 5.4.2 Safety-related drives
There are a number of drives, classified as safety-related category Class 1E to IEEE Standard 334, which are essential for the safety of the reactor during normal periods of shutdown or emergency periods following loss-of-coolant accidents which could involve severe
Power station auxiliary drives
1
F
F LOW STRAIGHTENER CONE I MPELLER
D.E. OIL BATH AND COOLER ROTOR 11kV MAIN MOTOR
415V PONY MOTOR
SPEED SENSING HEAD NON REVERSE CLUTCH
N.D.E. OIL BATH AND COOLER
I. G V. OPERATING SHAFT
ENO ENCLOSURE PLATE
I G.V. GEARBOX
FIG.
7.18 Sectional arrangement of a gas circulator 643
Motors
Chapter 7
-I - 1 I
4
•
A
'
TERMINALS
LOCATION OF MAIN MOTOR
STATOR WITHDRAWN FROM FRAME
OUTER FRAME
PERIM
CLAMPS
1
020.N.
gneaMONOM, AgrAr mismordoir ~roe I
•
4 V.
DRIVE END
AngarArg•
1111601111. -
411 44L
Medealte,
=1.111111111111111h k
°tit _ 11-roc
NON-DRISE ENO COILS
STATOR
FR,. 7.19 Gas circulator — main motor stator and outer frame
644
TERMINALS
LOCKING PLATE
Testing
PONY MOTOR ROTOR BALANCE WEiGHT
\\
1
1
—
FAN CLUTCH AND PULSFNG DrSC, ASSEMBLY
MAIN
:MPELLER
MOTOR ROTOR
Fu.j. 7.20 Gas circulator — main motor rotor
-Aliation, thermal and environmental stresses. The test -,quirements to be met in order to qualify or prove Jc2S[oT1 and reliability of such motors are given IEEE. 334. Examples are motors for centrifugal a Airing pumps, high head safety injection pumps and :t2st,lual heat-removal containment spray pumps.
5.5
Circulating water pumps
TABLE 7.5 Works tests on induction motors
Test Resistance of windings (cold) No load losses and current Locked rotor
— —
current torque
,...-
,..-- (_?..3.3 kV)
\
Rotor open-circuit induced voltage (slipring)
,.--
\
Direct-on start at full voltage (cage motors)
Routine
\
Starting (run-up) torque characteristics for cage motors over 375 kW
Basic \ \ 1 1
ii c usual arrangement of the cooling water system is system, in which the cooling water is taken to a ,tommon chamber whence a number of pumps dis.ii.iree into a common bus-main supplying all the conrisers in the station. In view of the vital importance tit the cooling water to the station output and in preplant damage due to loss of cooling water, spare capacity is installed. i - }1,2 motors are usually of the cage induction type. some installations use vertically-mounted motors, , , ii cre-as others are horizontal. Figure 7.22 shows a vertical-shaft circulating water pump motor. The .:iips are usually of low speed (typically 500 down to r min). With pump speeds lower than about 500 - ruin, it is usual to provide a motor driving through a cd-reducing gearbox, this being the most economic saratieement. rite more usual arrangement is to provide a pumpsometimes with removable or sliding roof for tii. Mitenance purposes. Both drip-proof and totally.::,.iosed motors have been used. The tendency is the totally-enclosed type, which gives greater ittroteetion against contamination of the windings. At Power stations, the stator windings are some. mcs additionally of the sealed type to protect against saline conditions.
The development of new designs and techniques, new materials and component parts is a research and development activity. Verification of the properties, performance, etc., must be obtained and is usually achieved by a testing process. Simulation methods may have to be used in some cases where direct testing is not possible or practical, e.g., accelerated ageing tests on insulation systems, where, for example, a relationship between voltage, temperature and time to breakdown can be established and the tests made at elevated temperatures and voltages. Fatigue testing of bars of cage induction motors is another example, where such tests are made to establish the total number of starts that can safely be made during the life of the motor. Works testing on the completed motor needs to be made to verify that the motor is electrically and mechanically sound and that the stated performance characteristics are achieved. Such tests are categorised into basic and routine tests. Basic tests are in general made on the first motor of each type and routine tests on all other motors. Table 7.5 lists the individual test requirements for induction motors.
,--
Temperature rise test
6 Testing 2
' ling LI1I
can be categorised into two groups: developand works testing.
Maximum (pull-out) torque Vibration measurement Noise level
1 \ \ \ \
Power factor and efficiency Speed control (variable-speed slipring)
645
Motors
Chapter 7
cL,WHF.EL
RACIA L
"H.uST
NE 3 SEAL LEAK OFF
CASING
I 51PELLER
SUCTION NOZZLE
FIG. 7.21 Reactor coolant pump and motor unit
7 Future trends Motors for power station auxiliary drives are likely to continue to grow, both in power requirement and complexity. More emphasis is likely to be placed on the achievement of high reliability, due to increasing costs of unplanned outages, and on safety to personnel. This implies extension of and/or improvements to existing testing techniques and could include tests to determine the permissible number of direct-on-line starts in the life of cage induction motors. With increasing attention being given to the conservation of energy, improvement in operating efficiencies will be 646
sought. Improved materials will continue to be developed. These could include lubricating grease with a higher withstand-temperature and improved capability of insulation systems. The use of motors having brushes, sliprings and commutators is likely to continue to be avoided. An increasing use of AC variable-speed converter drives is forecast, particularly with improvements in techniques and reduction in cost of converter equipment. Linear motors are likely to find an increasing number of applications where linear motion is required, such as cranes and sliding doors.
Additional references
THRUST AND GUIDE CENTRIFUGAL BEARING
SWITCH
INSULATED PLATE
OIL INLET
CIL, DRAIN
OIL OUTLET
AIR INLET
OIL OVERFLOW
._ 11kV MAIN TERMINAL BOX
• - ,TRAL TERMINAL ACCESS COVER ----
THERMOCOUPLE TERMINAL BOX • ANTI-CONDENSATION HEATER TERMINAL BOX -
OIL FLOW INDICATOR R.NLET
AIR VENT
EARTHING
BRUSHGEAR
VERTICAL INSULATED OIL OVERFLOW GUIDE PLATE BEARING
' OIL DRAIN
FIG. 7.22 Circulating water pump motor
8 References 11:4r,
Pl.: The nature of polyphase induction machines:
\111c•+,,y 195/
PI,: Induction machines, 2nd Edition: Gordon & lireach: 1970 1983
9 Additional references
\ I 0.: .kIternating current machines, London.: Pitman:
Id1,11S, 3. and Gibbs, W.J,: Polyphase commutator machines: C.imbridee University Press: 1951
'I
arc, K.K.: Performance requirements and test methods for :11 0-1 ,, oltage a.c. rumor insulation: Proc. LEE, Vol 116, No. 10: l 55
.5)
Schwarz, K.K.: Design and performance of high and [ow voltage
9.1 ESI Standards ESI 44-3 Electric motors specification 13.3 kV and above) ESI 44-4 Electric motors specification 1415 V and below) ESI 44-5 Testing the insulation systems for stator coils for rotating electrical machines 13.3 kV and above).
9.2 CEGB Standards — Electric motors — small power
i;:rinical hoses: Proc. LEE, Vol 109A p 151: 1962
CEGB 44011 (GDCD 851
,;,[w.arz, K.K.: Submerged gas circulator motors for advanced Ns-,:coted reactors: Proc. [E.E, Vol 120, No 7: July 1973
CEGB 620106 (GDCD 192) — Glandless pump/motor units electrical and mechanical design requirements
647
Motors
9.3 BS2757
Chapter 7
British Standards Classification of insulating materials for electrical machinery on the basis of thermal stability in service
BS4999
General requirements for rotating electrical machines
Part 10
Standard dimensions
Part 20
Classification of types of enclosure
Part 21
Classification of methods of roofing
Part 30
Duty and rating
Part 32
Limits of temperature rise and methods of measurement
Part 33
Methods of determining losses and efficiency
Part 41
General characteristics
Part 50
Mechanical performance — vibration
648
Part 51
Noise levels
Part 60
Tests
BS 5000
Rotating electrical machines of particular types
Part 40
Motors for driving power station auxiliaries
9.4
IEEE Standards
IEEE 334
9.5 IEC 34
Type test of continuous duty class IF motors for nud power generating stations
IEC Recommendations Rotating electrical machines Parts 1, 2 and 4 to 10.
ea ,
CHAPTER 8
Telecommunications and policy
Requirements to off-site services • • Acce.ss Requirements on the power station site General telephone requirements : 2i i 2 2 Radio systems 23 Radio paging system Operational telephone systems '2 4 Maintenance and commissioning communication '25 system 6 Audible warning system 1 2 Special requirements for nuclear and pumped-storage •3 cower stations • 3 1 Nuclear power stations 3 2 Pumped-storage power stations ' 4 Accommodation and power supplies Main telecommunications room INITRI 4 Auxiliary telecommunications room (ATM '4 2 7
1
PABX room 4.4 48 V DC power supplies 43
2 Access to British Telecom national cable network 2 1 On-site British Telecom cable requirements 22 On-site duct routes for British Telecom cables 2 3 Segregation of British Telecom cables within the power station building 2 4 British Telecom cables 25 Electrical isolation of British Telecom circuits 3 British Telecom telephone services 3 1 Public switched telephone network IPSTN) Telex 33 Data 3 4 Private circuit network
32
a On-site telecommunication cabling 1 General .1 2 FAX telephone cabling .1 2 1 Main distribution frame and station PAX telephone .1 2 2
odbling User distribution frame in the station administration pudding for the PAX/PABX telephone cabling
1 3 Short time fireproof cabling 4 4
t.ovi smoke cabling
5 Private automatic exchange (PAX)
5
Types of telephone exchange ' I Strowger systems 2 Crossbar systems 3 Stored programme control (SPC) systems
6 Private
automatic branch exchange IPABX1
1
7
7.3.5 Direct speech 7.3.6 Use of paging systems
8 Radio systems 8.1 Introduction 8.2 Radiotelephony systems 8.2,1 Radio frequency bands used by PMR systems 8.2.2 Comparison of VHF and UHF systems 8.2.3 Allocation of radio channels 8.2.4 VHF systems used in power stations 8.2.5 UHF systems used in power stations 8.3 Crane radio systems used in power stations 8.3.1 Crane control systems 8.3.2 Anticollision systems 8.4 RF modulation systems 8.4.1 Amplitude modulation lAM) 8.4.2 Frequency modulation (FM) 8.4.3 Signalling systems 8.5 RF propagation 8.5.1 RF received power 8.6 Antenna systems 8.6.1 Antennas 8.6.2 Typical antenna arrangements 8.6.3 Radiating cable (leaky feeder) 8.7 RF fixed stations 8.7.1 Fixed station transmitters 8.7.2 Fixed station receivers 8.7.3 Antenna coupling equipment 8.8 Lightning protection 8.8.1 Antenna systems 8.8.2 Fixed station cubicle 8.9 Remote control systems 8.9.1 Operational description of the M87 control system 8.9.2 Operational description of the Motorola-Stomp CAF2200 system 8.10 Handportable radiotelephone transceivers 8.11 Vehicle-mounted radiotelephones 8.11.1 Vehicle antennas 8.11.2 Noise suppression 8.12 Interference problems 8.12.1 Intermodulation products 8.12.2 Half IF interference 9 Direct wire telephone systems 9.1 General details 9.2 Common equipment and common equipment accommodation 9.3 Plant telephones 9.4 Audible and visual calling units 9.5 Common equipment location and battery supply
Genera i facilities 6 2 Night service facilities
1 0 Maintenance and commissioning telephone jack system
Paging systems
11 Siren system
7
'
Lghts and sounders 22 Inductive loop paging systems 1 3 Radio paging systems 731 Component parts of a non-speech radio paging system 32 Central control equipment 7 33 Manual controllers 7 34 Transmitters and antennas
11.1 Station emergency zones 11.2 Emergency alarm signals 11.3 Control panels 11.3.1 Operation of system from power station central control room controller 11.3.2 Operation of system from gatehouse controller 11.4 Equipment cubicle
649
Telecommunications 11.5 11.6
Power supplies Cabling
12
Central control room supervisor's desk
13
Nuclear power station requirements 13.1 13.2 13_2.1 13.2.2 13 2.3 13.2.4 13.3 133_1 13.3.2 13.3.3 133,4 13.4 13,4.1 13.4.2 13.4.3 13.4.4 13.4.5
1 4
14.4.4 Controllers 14.4.5 Fixed stations 14.5 Sound-powered telephone systems 14.5.1 System 1 — 400 kV cable tunnel system 14.5.2 System 2 — Power station emergency telephone system 14.6 Maintenance and commissioning telephone jack system 14.7 Siren system
Specific requirements for nuclear stations Public address systems Power station zones Controllers Common equipment
15
Loudspeakers
Private automatic branch exchange Private automatic exchange Radio paging system Personal radio system Antenna system Radio channels Handportable radiotelephones
1 Requirements and policy Reliable telecommunication services are essential for the efficient operation of a power station during normal and emergency conditions. To ensure the required availability of telecommunication services at all times, it is CEGB policy to provide separate, dispersed, independent and, where necessary, duplicated telecommunication systems. The term telecommunications in respect of a CEGB power station covers the following: • Telephonic communication on site.
Construction site telecommunications 15.1 Initial requirements for British Telecom services to sile 15.2 On-site telephone cable duct network 15.2.1 General requirements 15.3 Telecommunications systems and services 15.3.1 Private automatic branch exchange (PABX) 15.3.2 Emergency telephone system 15.3,3 Site emergency warning system 15.3.4 Pay telephones 15.3,5 Radio paging system 15.3.6 Site radio system 15,3.7 Radio telephone handportables 15.3.8 Data, telex and facsimile services
Siren systems Siren signals Controllers Common equipment Cabling and power supplies Emergency telecommunications Nuclear incident Emergency control centre (ECC) District survey laboratory (Dal Operations support centre (OSCI Radio services for a nuclear emergency
Pumped-storage power station requirements 14.1 14.2 14.3 14.4 14,4,1 14.4.2 14.4.3
Chapter 8
16
Future trends and developments 16.1 16.2 16.3 16.4 16.4.1
17
Connections to off-site telecommunication networks On-site cabling Telephone exchanges Radio systems Trunked radio system
Additional references
• To the associated 400 kV or 275 kV switching station (which may be on-site or off-site), through which the bulk of the power station electrical output is fed into the 400/275 kV national grid tranmission system. • To the public switched telephone network (PSTN) operated by British Telecommunications plc (BT) (the main British national telephone company) and also to the BT national cable network. • To the emergency services, i.e., Police, Fire and Ambulance.
• Telephonic communication to locations outside the power station.
• To the CEGB corporate telephone network (CTN).
• Radio paging of staff on site.
1.2 Requirements on the power station site
• Radio communication both on-site and off-site.
A number of telecommunication systems are provided on site to ensure diversity and reliability of operation.
• Audible and visual broadcast of information and emergency instructions.
1.2.1 General telephone requirements
1.1 Access to off-site services Good communication links are required from power stations to the following locations and services: • To the national grid system operations control and telephone network; and in particular, to the area grid control centre from which the power station receives generation and operational instructions, details of which are found in Volume K, Chapter 12. 650
Telephonic communication is required to power station on-site locations and to remote locations. It is present CEGB policy to satisfy these requirements by providing two separate automatic telephone exchanges: a private automatic exchange (PAX) and a private automatic branch exchange (PABX), which have interconnecting circuits. A small number of direct telephone lines to the PSTN are also provided which are inde pendent of the station exchanges.
Requirements and policy FAX system has telephones at all parts of the T he ltion and provides telephonic communication facifor the general administration of the station. The :; sv.stem also has an operational function which , °\ power station discrete direct wire op,,plements the systems referred to later in this ii al The FAX has access to the national CEGB
si
thorities to mean one or more contiguous power stations and therefore the five channels, where authorised, would be shared between all the power stations.
1 1 1
neto.orks, i.e., system operation telephone the CEGB CIN, and also direct circuits to Ier off-site CEGB PANs and telephones. FABX system provides access to the BT PSTN. allocation of PABX telephones is generally reto those locations needing such access, mainthe Station Administration Building. The lines 1% in PABX and FAX permit intercom,. orriccting the inunication between all PABX and FAX telephone e
mensions.
\ceess of individual PAX telephones to off-site loeJtions is allocated on a 'need to use' basis, as is :lie access of individual PABX telephones to the BT HT. Nominated locations and personnel have both PABX and FAX telephone which provides direct ,..,.,,,, mun ication with both telephone exchanges. o separate telephone exchanges are provided be_lase present Department of Trade and Industry (DTI) cnilations prohibit the CEGB from maintaining a r telephone exchange which has access to the BT PSTN. I - he telephone exchange must be maintained by an •.i rproved maintainer' which can be HT or, alternativeh., the supplier of the telephone exchange. However, ilie CEGB requires the option of carrying out emernc ■ repair work immediately, using its own staff. [his is achieved by providing a PAX completely under NGB control for telephone communication to all .ration locations and a separate PABX for those and personnel authorised for access to the BF PSTN which is maintained by BT or another appro ■ ed maintainer. A failure of the PABX cannot rc,:ek,e attention until the off-site maintainer attends 'i c fault. The use of two telephone exchanges located in Fir ierent areas of the power station, e.g., FAX in the .,)nirol building and the PABX in the station ad:Tnnistration building, also improves the reliability of idephone communications by providing spatial and ektiipment diversity.
1.2.3 Radio paging system A radio paging system (RPS) enables users of FAX telephones, the telephone operator and the station control engineer to access the paging system and page individual roving personnel carrying pocket pagers. The paged person will establish speech communication with the caller by using a convenient FAX
telephone and dialling the common answering code for the paging system. On present systems, the pocket pagers have an alphanumeric display which is programmed by the caller to show the telephone number which the paged person should call. The operating procedure adopted by the caller would be to: • Key/dial the RPS access number on the PAX. If this is successful, an acknowledge tone will be received from the RPS. • Key/dial the desired pager number. A supervisory tone will indicate acceptance of the pager code by the RPS. • Key/dial the callers telephone number which is to be displayed on the pager. • A supervisory tone will indicate that the paging call has been accepted. • Replace the telephone handset and await the call back from the paged person. The radio paging system is also used to alert groups of personnel, i.e., the first-aid team, the fire fighting team and, in nuclear power stations, the damage assessment teams. 1.2.4 Operational telephone systems
Discrete, direct wire operational telephone systems are provided for each unique plant system, e.g., boiler/ turbine unit and associated plant, electrical plant and coal plant (where appropriate).
1.2.2 Radio systems
1.2.5 Maintenance and commissioning
Radio communications are provided by fixed base sta-
communication system
lon receivers and transmitters remotely controlled from JeNk or table top mounted controllers and handportable radiotelephones (handportables) carried by roving personnel. Roving personnel carrying handportables are :t ko able to speak to each other via a fixed station, ia , ing the 'talkthrough' facility. UP to five separate radio frequency channels are ailable for use at a power station site. The term Power station site' is understood by the licensing au-
A network of direct telephone circuits terminated on telephone jack sockets are provided on (or near) power station plant, control desks, etc., where direct telephone communication is required during maintenance and commissioning of station plant. Station personnel use portable telephones or amplified headsets plugged into the telephone jack sockets. The network is referred to as the maintenance and commissioning telephone jack system (MCTJS). 651
Telecommunications 1.2.6 Audible warning system
An audible warning, to inform all power station personnel of an emergency, is provided by operating sirens in either the discrete area(s) of the power station affected or in all areas of the power station. The opera[i on of the sirens is controlled from the power station control room and 'or the security gatehouse.
Chapter 8 In accordance with present telecommunications practice, computer type flooring, i.e., removable floor squares, is provided in all three rooms for convenience of cabling and future changes of equipment. Although, generally, telecommunications equipment is becoming s maller, the quantity of equipment is increasing. 1.4.1
1.3 Special requirements for nuclear and pumped-storage power stations Nuclear and pumped-storage power stations need special telecommunication facilities not found in conventional fossil-fuelled stations. 1.3.1 Nuclear power stations
Main telecommunications room {MTR}
The MTR has a floor area sufficient to accommodate the known and future equipment. Over-provision of space is desirable because of the inability to make accurate forecasts of future requirements which in the telecommunication field are subject to continuous change. The MTR has an adjacent battery room. A typical layout of the two rooms is shown on Fig 8.1. The MTR has cable routes to the main cable risers and cable tunnels for access to:
Safety and emergency conditions in the reactor area require consideration of:
• The power station digital pair network.
• Safety of personnel and plant.
• Telecommunications cable routes to the associated 400/275 kV switching station.
• Control of emergency operations. • I mmediate dissemination of information to personnel during emergency conditions. • Communication with off-site nuclear incident emergency services. • Dissemination of information to the general public during a nuclear incident. • Radio communication within and into the reactor areas of the power station. 1.3.2 Pumped-storage power stations
Safety and emergency conditions in the underground areas of the power station require consideration of: • Safety of personnel and plant. • Communication with roving personnel in all areas of the underground labyrinth.
• Each of the two physically separated incoming BT cable routes. Access for equipment and personnel into the \ITR is provided by a double door. A second door is used for access of personnel and as an emergency exit. Consideration is required of the access and equipment handling facilities available on the route to the NITR double door within the station. The environmental conditions of dust and humidity must not at the present time be less than those applicable to the Central Control Room (CCR), as specified in Specification CEGB-EES (1980), Clause 2.2, Table 1, Class B3. The temperature of the room should be maintained within the limits of + 5 ° C to + 40°C, allowing for a maximum heat dissipation of 10 kW from the equipment in the MTR. With modern SPC exchanges, air conditioning is provided for the MTR to give Class A conditions, i.e.: • Temperature limits of + 18 to + 27 ° C.
1.4 Accommodation and power supplies
• Relative humidity limits of 35 to 75%.
In fossil-fuel power stations, three telecommunications rooms are provided for diversity and security of alternative operational communication system equipment: two in the \lain Station Building, i.e., the Main Telecommunications Room (MIR) and the Auxiliary Telecommunications Room (ATR), and one in the Station Administration Building (PABX room). In nuclear power stations an ATR is provided for each reactor/turbine-generator unit. The telecommunications requirements change during the life of a power station and adequate space is specified at the design stage to ensure that future changes and additions to equipment can be accommodated.
SPC exchanges which have been approved to the requirements of the CEGB General Specification for Electronic Equipment (CEGB-EES 1980), will continue to operate within Class B temperature and humidity li mits but with the possible reduction in equipment ti ming and other minor variations in the manufacturer's specified equipment operational limits. To supply the MIR and the associated telecommuni cation battery charging requirements, two alternative 7.5 kW, three-phase, 415 V AC supplies are requiredto feed two 6-way, three-phase and neutral distribu tion boards complying with CEGB Category 2 safety
652
Requirements and policy
jm
BATTERY I
500
500 V
SUSPENDED LIGHT FITTING
- 2540
SiNK 800
BATTERY 2
48V FUSE LINK BOX
MOUNTED B T LINKS SA
1580
-4--
690
—1 ""
.1-
MAIN D , STRIKTION FRAME LINE SIDE
700
48V DISTRI BUTION BOARD
700
48V CHARGER No 2
48V CHARGER No 1
EXCHANGE SIDE
TELETYPEWRITER 550
700
7
'00
800
1
FAX
LINE
-41-
550
, _ _ ___I
_
GENERAL INDICATIONS
550
UHF RADIO
a—
550
_t_
f
—
UHF RADIO
VHF PAGING
240V AC SWITCHED SOCKET OUTLETS INTERFACE FOR CORPORATE TELEPHONE NETWORK
1
1
BENCH
FIG. 8,1
Main telecommunications room — typical floor plan
-
-duirernents. Each of the two battery chargers is ;i Flieci from different AC supply distribution boards. 110 V 50 W AC uninterruptable power supply I N is required for the radio paging central control :quipme nt. -
11
1c minimum lighting standard is 300 Lux. li ghting is also provided;
MTR equipment The equipment includes cable distribution frames, PA(B)X, UHF radio equipment, radio paging equipment, 48 V DC power supply equipment, isolation equipment for BT incoming cables, CTN equipment and grid control telecommunications equipment (for 653
Telecommunications
Chapter 8
grid system control and telephony) when the latter is not located in the associated 275 kV or 400 kV switching station. .11TR 48 V DC power supplies If Plante batteries are used, the 48 V power supply equipment comprises: two chargers, two batteries and a single distribution board. The power supply system has sufficient electrical capacity to supply the known and predicted 48 V DC requirements of the 1V1TR. For a modern power station this would include two batteries of approximately 400 Ah each. The arrangement complies with CEGB Transmission Plant Standards. A simplified block diagram of the system is shown in Fig 8.2. The two batteries and chargers are operated in parallel. Failure of one battery or one charger will not cause a complete failure of the system. Each charger has sufficient output to meet the total battery load. The two paralleled batteries are capable of supporting the load for approximately 12 hours. The arrangement enables one battery and charger to be disconnected from the load for off-load boost charging. During boost charging the standby capacity of the system is halved, e.g., it is approximately 6 hours. The 48 V positive poles of the batteries are earthed at one point, usually at the distribution board via an isolating link. An earth cable is run between the distribution board and the power station's control and instrumentation (C and I) earth. The C and I earth is also used for the cable screen earths associated with the power station multipair cable distribution system. AC . SUPPLY
A C. SUPPLY
The Plante batteries are located in a battery roo m adjacent to the MTR. The room complies with the CEGB standards for battery rooms described in Chapter 9. If recombination cell batteries are used, the 48 V DC power supply equipment is provided for each individual telecommunications equipment. A power equipment rack (PER) comprising modular rectifiers and .48 V battery units is provided ensuite with its associated telecommunications system. Each modular battery h as a capacity of approximately 100 Ah. A number or rectifier/battery modules are connected in parallel to provide the required standby capacity, e.g., 12 hours for a PAX, DWTS or AWS and 7 hours for a PABX. The advantages/disadvantages of recombination cells are described in Section 1.4.4 of this chapter. 1.4.2 Auxiliary telecommunications room (AIR)
The AIR is remote from the NrITR and provides accommodation for telecommunications equipment associated with each turbine-generator unit, whereas the MTR provides accommodation for non-unitised telecommunications equipment. In the event of a fire in the MTR, the telecommunications in the ATR will be unaffected and vice versa. Nuclear stations have one ATR per turbine-generator unit to provide further separation and the enhanced security which arises from dispersed and diversified systems. With the exception of the unit MCTJS which uses the station multipair cable system, the ATR equipment uses dedicated cable systems. The ATR is dimensioned to accommodate the following telecommunications equipment: • A public address system (for one of the duplicated systems). • An audible warning (siren) system (AWS). • A maintenance and commissioning telephone jack system (MCTJS).
DUAL BATTERY CHARGERS
• A direct wire telephone system (DWTS). One of the ATRs will also accommodate the DWTS for the CCR supervisor's desk in addition to one of the turbine-generator unit systems. —11 DUAL 400AH BATTERIES
48V DISTRIBUTION BOARD
48V0C SUPPLIES FOR MCR EQUiPMENT
Ho. 8.2 Main telecommunications room — 48 V DC power supplies block diagram 654
Where there is a requirement at a nuclear power station for seismically qualified DWTSs, then the central DWTS equipment must be seismically qualified and located in a seismically qualified room. The AIR battery which provides power for the DWTS and the other telecommunication equipment in the ATR must also be seismically qualified. Figure 8.3 shows the floor plan of one of the two ATRs for a two-unit nuclear power station, where seismic qualification of the DWTS is required. Where seismic qualification is not required, the DWTS equip- ment is located in the same room as the other telecom munication equipment.
Requirements and policy
4m
LI
BATTERY ROOM
SUSPENDED LIGHT PITTING
2 5rn
48V BATTERY iSEISMICALLY QUALIFIED) -
r
LJL48V BATTERY FUSE AND LINK BOARD
SINK
6 WAY SINGLE PHASE DISTRIBUTION UNIT
CHARGER AND DISTRIBUTION BOARD
DIRECT WIRE TELEPHONE SYSTEM
SEISMICALLY QUALIFIED EQUIPMENT
240V A.C. SWITCHED SOCKET OUTLETS
ADDRESS (P A )
MAINTENANCE & COMMISSIONING TELEPHONE JACK SYSTEM PATCHING BOARD 30 WAY CHARGING RACK FOR RADIO HAND PORTABLES
Fic, 8.3 Auxiliary telecommunications room
typical floor plan of' a unit ATR for a nuclear power station having a seismically qualified direct wire telephone system —
655
Telecommunications
Chapter 8
A TR 48 V DC power supplies If Plante batteries are used, the 48 V power supply equipment comprises: a single charger, a battery and a single distribution board. The power supply system has sufficient electrical capacity to supply the known and predicted 48 V DC requirements of the ATR. For a modern power station the battery would be of the order of Itto .1h. The arrangement complies with CEGB Transmission Plant Standards. A simplified block diagram of the system is shown in Fig 8,4, The earthing arrangement is similar to that described or the NITR 48 V power supplies. If recombination cell batteries are used, the rectifiers and batteries are provided and sized to suit the associated telecommunications system as explained for the 14TR.
AC SUPPLY
SINGLE BATTERY CHARGER
48V CPSTRIBUTION BOARD
1.4.3 PABX room The PABX room and the associated battery room (when required) are located in the power station administration building. The rooms should have sufficient floor area to accommodate the known present and future equipment requirements. The PABX room accommodates the PABX, battery charger, 48 V distribution rack or power equipment racks (PERs), cable distribution and isolation frames, maintenance terminal and miscellaneous furniture. When the battery comprises lead acid Plante cells, a battery room is provided to accommodate the 48 V DC battery and battery maintenance equipment. The cable distribution frames located in the PABX room include the Network Operator's Distribution Frame (NODF), the User Distribution Frame (UDF) and the Test Jack Frame (TJF). The NODF is the termination point for the network operator's off-site cable connections. The UDF is the termination point for the on-site PABX telephone cable system. The TJF is the termination point for the PABX cables and interconnections between the PABX, the NODF and the UDF. All three distribution frames have a jumper wire system to enable the flexible interconnections to be made. The cables terminating on the UDF include cables to: the floor distribution points (FDPs) in the station administration building; the local distribution boxes; the locally sited line jack units (LJUs) for telephones; the PABX swjtchboard(s) in the reception area of the station administration building; the MTR in the station control building and the supervisor's desk in the CCR. In the case of 'hot' sites, i.e., sites which have poor earthing systems allowing the earth point potential to rise during high voltage (HV) to earth faults, an isolation frame is inserted between the NODF and the cables connected to the off-site network operator's cable distribution system. This is unnecessary for sites served solely by fibre-optic cables. The isolation frame can 656
48v DC SUPPLIES TO ATCR EQUIPMENT Fio. 8.4 Auxiliary telecommunications room — 48 V DC power supplies block diagram
be free-standing or wallmounted and accommodates cable pair isolating links and isolation transformers. Alternatively, the links and transformers can be provided as separate wall-mounted units. The definition of a 'hot' site is given in Engineering Recommendation S5/1 Section 6.1. From the Recommendation it can be seen that isolation equipment is necessary if the earth potential rise is greater than 430 V RMS for systems protected by overcurrent protection and 650 V on 'high reliability systems', i.e., systems having high speed protection. Typical wall-mounted isolation units are described in Section 2.5 of this chapter. The PABX room is also used as the marshalling and terminating point for cables connected to station telecommunication services, access to which is required within the station administration building, e.g., the station public address system, the station radio paging system and the PAX telephone system. The environmental conditions in the PABX room should be similar to those of the MTR to provide the correct environment for the PABX. A reliable AC power supply is required into the PABX room to provide power for the PABX battery charger and other telecommunication equipment. An AC power supply is also required for wall-mounted sockets in the PABX room for portable test equipment, the PABX interrogating and programming terminal and portable cleaning equipment. A low resistance connection is provided to the AC power supply earth located as near as possible to the power supply cable entry to the Administration Building. This earth connection is extended to the PABX positive connection of the 48 V DC battery or to the
Requirements and policy ---All 48 V DC positive connections in the PABX pERs. are taken to this single earth point and are isolated oin the PABX cabinet earth to avoid multiple earths (l 48 V DC positive, which can result in noise on t h e ss-talk interference. .1 nd 1.4.4 48 V DC power supplies cell batteries V DC power supplies have traditionally used Plante 4 ,, Ii batteries. The power supply system has comprised one or tv,o 48 V batteries, one or two chargers and a r.useLl distribution board. The 48 V power supply system positive has been earthed at one point only, i.e., at the 48 V distribution hoard. Here, an earth cable has been taken to the ro\ker station C and I earth system. The 48 V batteries for the MTR and the ATR have ,Lifficient electrical capacity to provide a minimum of I ' hours' standby for the total 48 V DC installed load, ,Irid for the anticipated growth In the load over the r o rcseeable future. Recombination cell batteries 48 V DC power supplies which use recombination cell batteries are provided as an integral part of the in,Ialled equipment with each telecommunications sysern, The batteries are provided with sufficient capacity TO `,upply the associated telecommunications system.
are ideal for a rapid reaction between the spongy lead and the oxygen to form lead oxide: 2Pb + 0/
.
(8.1)
The lead oxide in the acidic conditions easily goes to lead sulphate: 2Pb0
2H , SO 4 = 2PbSO 4
2H20 (8.2)
Since the lead sulphate is deposited on the surface of the electrode which evolves hydrogen it will be reduced to lead and sulphuric acid: 2PbSO 4
2H2 = 2Pb + 2H2SO4
(8.3)
Adding Equations (8.1), (8.2) and (8.3), and cancelling similar terms on both sides of the resulting equation produces: 2H2
02 = 2H20
(8.4)
This reaction is gas recombination. Provided the process is 100% efficient, a method is available to recombine the gases produced by overcharging within the lead acid battery. For production batteries, recombination efficiencies of better than 96% have been quoted. The recombination efficiency is based on the amount of hydrogen lost to the system and can be expressed by the method proposed by Harrison and Whitley in the following equation
(ias recombination in lead acid cells Hie negative plate in a lead acid cell consists of a lead alloy lattice or grid in which the spaces of the grid ire filled with chemically-active lead sponge. If a fully ilarged negative plate is removed from the acid and exposed to the air it will heat up rapidly, produce earn from the water on the surface and quickly form ,i deposit on the surface. During this chemical reaction, orgen from the air reacts with the lead to produce oxide (Pb0) and heat. The significance of this is that a fully charged ne2Luive plate is highly reactive with oxygen. This is the INisis of lead acid gas recombination cells. When a J1312C current flows through a fully charged lead acid electrolysis of water occurs to produce hydrogen or -a the negative electrode and oxygen from the posii‘e electrode. The evolution of the oxygen and hydro'.,==r) gases does not occur simultaneously because the i: Nciency of the recharge of the positive electrode is :t ot as good as that of the negative. This causes oxygen oke from the positive plate before hydrogen is olved from the negative plate. \s the oxygen is evolved from the positive electrode, :here is a substantial amount of highly active lead Tonge existing on the negative electrode before hydrocommences to evolve. Therefore, provided oxygen On be transported to the negative electrode, conditions
2Pb0
R—
I — IH
x100%
where R is the gas recombination efficiency I is the average charging current which passes through the battery during test I H is the average current equivalent, under Faraday's law, of hydrogen emitted during the test period Since the hydrogen arises from the electrolysis of water an equivalent quantity of water is lost to the battery, giving rise to an equivalent loss of oxygen. There are a number of theories of how the oxygen is removed from the battery. The most popular are corrosion of the positive electrode or sulphation of the negative electrode. The former would reduce conductivity of the positive electrode and the latter would reduce the capacity of the negative electrode. Loss of water would also affect the capacity of the cell. Each has a direct effect on the operational life of the battery. Although referred to as sealed cells, a vent is provided to allow hydrogen to escape and prevent a dangerous build up of pressure inside the battery. The recombination efficiencies obtained from the Harrison and Whitley technique have indicated that 657
Telecommunications
Chapte r 8
the operational life of the batteries is of the order of 10 years. The electrolyte is absorbed by a fibre-glass separation material between the plates. This allows free movement of gases between electrodes and with the vent removed \\ ould result in little or no electrolyte escaping because it would be held by the absorbent separation material. A ("vantages
of recombination cell batteries
• A specially designed battery room is not necessary. • Size, suitable for locating in equipment rooms. • Ease of handling during installation. • Lower level of maintenance. • Low level of hydrogen liberated during charge. Disadvantages of recombination cell batteries • Lower operational life, 10 years compared to 25-30 years for Plante cell batteries. • Difficult to determine the state of the battery, i.e., capacity available for an emergency. • Lower level of maintenance required can lead to abuse of the battery by personnel assuming that the batteries are maintenance-free. CEGB requirements for recombination cell batteries Until the CEGB has accumulated a similar amount of operational experience to that for Plante cells the following requirements are specified. The power equipmeat racks (PERs) shall be provided with: • Low volts alarm relay or equivalent across 48 V busbars (set at 43 V). • High volts alarm relay or equivalent across 48 V busbars (set at 60 V). • Low volts disconnect load relay or equivalent (set at 41 V). • isolation facilities to enable disconnection of the rectifier output and load to each 48 V battery module. • Facilities to enable open-circuit volts to be measured on each 48 V battery module in turn, allowing the remaining paralleled 48 V battery modules and rectifiers to supply load. • Facilities to enable current flowing into each 48 V battery module to be measured. • Facilities to enable current flowing out of each 48 V rectifier to be measured.
• A
calibration graph for each 48 V battery module showing open-circuit volts against discharged ampere hour capacity, see Fig 8.5.
658
40 60 90 DISCHARGE AMPERE.HOURS CAPACITY-I00
'30
Fa. 8.5 Battery terminal voltage plotted against depth of discharge
These facilities will enable the recombination cell battery to be monitored and the available capacity to be determined. For further details on batteries see Chapter 9.
2 Access to British Telecom national cable network As British Telecommunications plc (BT) is the main telecommunication carrier in the United Kingdom, access to the BT national telephone cable network allows the use of the wide range of BT telecommunication services. The main service is the public switched telephone network (PSTN), which provides telephone services to all United Kingdom and international telephone users and access to the sophisticated telecommunication services now available on the BT PSTN. The CEGB also makes use of the BT national cable network for telecommunication circuits to locations external to the power station for telephony, data, grid system control, telecommunications and grid system protection. BT provides telephone cables from the power station telecommunication rooms to two segregated points outside the boundary of the power station site and arranges for segregated routing of cables from the two off-site segregated points to the BT cable network. This is to reduce the probability of a common mode
Access to British Telecom ffeCtmg all circuits and services provided jie failu1' the power station will not be subject to - l3T. i C., image occur to one of the cable t
1C
i0U
es5 from tl1CS points is required to BT high rOIJ'' sometimes over long distances, •1ui('. , en colitrol, telecomfflufliCatiOnS and HV • .rid li ne protection equipment. It is usual to ,1i:ernatk clv routed circuits to locations O maintain tekcommunicahi h t is essential to all times, such as to the system operaiCeS at rid control centre and the distant ends of the ransnsiS50 lines connected to the power station iv riJ Line protection. If two circuits are required rcmot location, then BT are instructed to segre.1 circuit iron' the other through the entire cue cable network to minimise the risk of r e!cpho , nuitaneous loss of both circuits.
2.1 On-site British Telecom cable req uirements va segregated routes are provided on-site to the il oing locations: • Station MTR. • -tation administration building (PABX room). • 400/275 kV switching station telecommunications room (if on site). UT cables are also routed on site between the above l, it ionS for interconnection of BT circuits. Typical jrrangemerits are shown on Fig 8.6.
national
cable network
2.2 On-site duct routes for British Telecom cables To provide segregation and protection for the BT cables on-site, two segregated duct routes are provided from the BT off-site points to the various on-site telecommunication rooms. The provision for each route is a minimum of two 100 mm PVC type ducts, \ith carriageway boxes spaced along the route to facilitate the drawing-in of cable during installation and the replacement of cables. The carriageway box is specified because of its strong construction to ensure ihat it is not easily damaged by the weight of heavy vehicles, particularly during the construction period of the power station.
2.3 Segregation of British Telecom cables within the power station building The segregation of the two BT cable routes is continued between the segregated access points into the power station building and to the MTR. At the design stage, two BT cable routes are planned to provide the required segregation and the cables are routed in unplasticised PVC cable trunking. This provides a degree of mechanical protection of the cables and reduces the fire risk to the BT external-type telephone cables, which often have a polythene sheath.
2.4 British Telecom cables During the design stage of the station, the quantity and sizes, i.e., number of pairs, of the on-site BT cables
400 1V SUB STATION
STATION ADMINISTRATION BUILDING
TEL E CO MMUN IC AT IONS ROOM
ST OFF SITE CABLE ROUTE NO 1 TO ST CABLE NETWORK
U
BT OFF SITE CABLE ROUTE NO 2 TO ST CABLE NET WORK
MAIN ROAD
BT OFF SITE ROUTE NO USED IF APPLICABLE
FIG. 8.6
Diagram showing the
diversity
and separation of two cable routes on a power BT cable networks
station to the off-site 659
-1P Telecommunications
Chapter 8 •••■•••
are specified by the CEGB, based on the known and estimated future telecommunication needs of the station, thus minimising the need for additional or replacement FIT cables during the life of the station. BT regulations do not permit the jointing of on-site BT telephone cables directly connected to the off-site BT telephone cable network. This is to ensure that 13T personnel are not put at risk if the jointing of one of the cables coincides with a rise of earth potential at the power station site, during an electrical system fault in the power station, or the on-site 400/275 kV switching station.
2.5 Electrical isolation of British Telecom circuits All of the above BT cable pairs are terminated by BT on isolation links (BT reference, Links Isolation Type 5A) in the locations detailed in Section 2.1 of this chapter, to permit easy electrical disconnection of the cable pairs from equipment installed in the station. If the calculated rise of earth potential during electrical fault conditions exceeds 650 V AC RMS, then isolation equipment is provided on every working circuit to isolate the off-site BT circuits electrically from the power station telecommunication equipment. This prevents the transfer of the rise of earth potential but permits through-transfer of speech and signalling information, thus preventing damage to BT plant external
SEND
to the power station and also the transfer of electrical potential to BT personnel working on external Bi plant. Figure 8.7 shows a circuit diagram of an exchange line isolating equipment and Fig 8.8 shows a circuit diagram for isolating equipment typically used for grid system control, telephony and protection of telecom. munication circuits.
3 British Telecom telephone services A power station requires access to many BT servic es including the PSTN, telex, data and point to poi nt circuits.
3.1 Public switched telephone network (P SIN) The majority of the direct exchange lines (DEL) for the station will be routed to the nearest BT telephon e exchange. However, if the station is in a rural area it is often prudent, in the interests of reliability of service and security of access to associated I3T services, for the DELs to by-pass the local BT telephone exchange and to be directly connected into a BT telephone exchange serving an urban area. For additional security, a BT telephone on the supervisor's desk in the CCR has a DEL connected to an alternative BT telephone exchange to that serving the power station PABX. This ensures that access to the
} SEND
TO POWER STATION TELECOMS EOL)IP
CIRCUIT TO REMOTE SITE VIA BT CABLE NETWORK
\ R EC EIVE
FIG.
660
} RECEIVE
8.7 Transformer isolation unit for connecting power station telecommunications equipment to BT 4-wire audio circuits
On-site telecommunication cabling • Emergency speech circuits for fire and police services. Nuclear stations also require access to off-site nuclear emergency services.
5CaEEN
• 4,
• CEGB CTN circuits. 0:RGUIT TO > rEP:50 9NTE EXCHANGE
• Remote control of circuits for radio fixed stations located outside the power station. Access to the private circuit network of NrierL:ury Communication Limited (MCL), the second largest British public telecommunications carrier, is also used (s4tere available) to provide an alternative to the BT private
CA*
circuit network.
C
4
AA*
4 On-site telecommunication cabling
4.1 General *BELAYS CA AA HAVE HIGH INSULATION BETWEEN BELAY COILS AND CONTACTS
FiG.
8.8 Transformer isolation unit for direct BT telephone lines or PABX exchange lines
BT PSTN is available to the supervisor should the BT telephone exchange serving the station fail. The telephone number of this DEL is not listed in the BT telephone directory and it is referred to as the 'exdirectory out-of-area' telephone. This DEL is routed in the BT cable network both on and off-site, to provide diversity with the direct telecommunications circuit to the remote grid control centre. This gives an alternative means of speech commuhication between the supervisor's desk and the grid control if the grid control communication link is faulty.
3.2 Telex One telex machine is provided in the station connected to the BT telex network, its primary purpose being the transmission and reception of telexed information from locations not having access to the CEGB Corporate Data Network (CDN).
3.3 Data Access to BT data circuits is required, such as the
BT packet-switched service, for locations not having access to the CEGB CDN.
3.4 Private circuit network Access is required to the BT private circuit network
for: • Grid system operation circuits. • PAX and PABX exchange interconnection tie circuits.
Special factors related to the importance of a particular telecommunications system determine the type of cable used and its routing. The cables for PAX main cable routes, either dedicated or via the station digital pair network, have fire-retardant sheathed cables as detailed in Chapter 6 of this volume, and are as used for control and instrumentation cabling within the power station. The cable for the personal ultra high frequency (UHF) radio systems, the grid control emergency and nuclear emergency very high frequency (VHF) radio systems, the direct wire telephone systems (DWTS) and the siren system is short-time fireproof cable, which will remain serviceable in a fire area for a minimum period of 20 minutes.
4.2 PAX telephone cabling The power station digital pair network, which is detailed in Chapter 6, has multipair cable marshalling boxes in power station areas for the marshalling of digital circuits required by equipment located near to the boxes. The marshalling boxes are cabled to central marshalling cubicles which are interconnected with multipair cables to enable digital circuits to be routed between many areas of the power station. The PAX telephone circuits are routed by the digital pair network from station locations to the station MTR, where they terminate on the MDF. The PAX telephone circuits use dedicated 20-pair modules in the digital pair network. All pairs of each dedicated module are through-connected from a 20pair terminal strip on the MTR MDF to 20-pair telephone cable marshalling boxes in the station areas. Figure 8.9 shows a typical telephone cable marshalling box, dedicated for telephone circuit use only. For new power stations, at least 20% spare circuits (which are all through-connected to the MDF) are provided to each telephone cable marshalling box. 661
Telecommunications
Chapter 8
'A'
hr.
TO SCREW SCREW CLAMP TERMINALS FOR 8 PAIR CABLES TO TELEPHONE INSTRUMENTS)
40 WIRE WRAP SCREW CLAMP TERMINALS --FOR 20 PAP INCOMING CABLE
SCREEN CONNECTION TO TELEPHONE CABLES 10 SCREWSCREW CLAMP TERMINALS WITH COMMONING BAR FOR CABLE SCREEN CONNECTIONS
-
JUMPER RING
— T) t
etten rI7111
.1V
CABLES TO 20 PAIR TELEPHONES CABLE TO STATION DIGITAL MULTIPAIR NETWORK FIG.
GLAND PLATE
TELEPHONE
TMB TYPICAL LABEL FOR TELEPHONE MARSHALLING BOX
8.9 Typical telephone cable marshalling box
These may be used subsequent to the initial installation of the cable system to provide direct connections to the MTR MDF without having to interfere with the digital pair network interconnecting arrangements. 4.2.1 Main distribution frame and station PAX telephone cabling
The MDF in the MTR is the marshalling and terminat662
SECTION AA
ing point for the majority of telecommunication cables entering the MTR. The MDF is floor standing and has a line side (for termination of cables to the MTR), and an equipment side (for termination of cables to equipment in the MTR). The line and equipment sides are interconnected by single-pair jumpers as required. The line side is fitted with discrete 20-pair terminal strips having terminals for wire wrapping. Each block of terminal trips will
Private automatic exchange (PAX) accommodate one 20-pair module from the digital pair network, i.e., one through-route to a 20-pair :elephone cable marshalling box in the power station plant area. Other cables on the line side of the MDF are tollo ■ %s: N upervisor's desk in the CCR. • I00-pair cable to Three 100-pair ,:ables to the user distribution frame • (UDE) in the P Al3X room of the station administration building (for PAX telephones in the station administration building area, for PABX telephones in the power station and for power station plant bitildings outside the control building).
•
• Direct wired telephone systems. • UHF handportable radio telephone systems. • Siren control systems.
• Public address systems.
NIultipair cables to the BT incoming cable isolation rack.
4.2.2 User distribution frame in the station administration building for the PAX/PABX telephone cabling The user distribution frame (UDF) is located in the PABX room of the station administration building (described in Section 1.4.3 of this chapter) and is a ,in , le-sided wall-mounted frame fitted with 20-pair terminal strips, having insulation displacement terminals (1DTs) for cable and jumper wire terminations. These terminal strips are used for terminating all multipair cables to the floor distribution points (FDPs) in the station administration building, the cables being used for both PAX and PABX telephone circuits. The cables used for BT circuits such as DELs and data circuits, are terminated on the network operators distribution frame (NODF). These are BT network services required to individual locations in the station administration building or the main station buildings, which are directly connected (by isolation equipment %there necessary) to the BT national cable network. Department of Trade and Industry (DTI) regulations cc.iiiire that BT network services are routed in cabling separate from that carrying PABX/PAX extension C ircuits. This separate cabling requirement for BT network set:\ ices is designated as 'overlay cabling' and is aimed at the separation of BT network services from separately pros ided and owned PABX cabling. The PABX extension cabling must now comply with British Standard 8S6701, which details the requirements for cabling of PABX telephone extension cabling. It also specifies a separate isolated earth connection, referred io as a functional earth (FE), to each PABX telephone DP or cable marshalling box for use by PABX telephones where the PABX requires an earth connection or certain PABX telephone functions, i.e., recall .i Terator, transfer call, etc. This isolated FE connection :s earthed at the PABX room only. 4
turers, a cable which provides a 20-minate withstand of temperatures up to I000 ° C. The mechanical and electrical properties of the cable are given in GDCD Specification 195 and are described in Chapter 6. Short-time fireproof (STFP) multipair cables are used for the following telecommunication systems:
.3 Short-time fireproof cabling
The CEGB has developed, with the cable manufac-
4.4 Low smoke cabling The CEGB and the cable manufacturers have jointly developed a cable which has low smoke and halogen emission properties when burnt. This type of cable reduces the risk to personnel during a fire and reduces the damage caused to electrical and mechanical equipment due to the production of hydrochloric acid from the halogens. The cable is used extensively in the CEGB PWR nuclear power stations for telecommunication on-site cabling in place of PVC multipair cables. Details of the mechanical and electrical properties of these cables are given in GDCD Technical Specification and are described in Chapter 6.
5 Private automatic exchange (PAX) 5.1 Types of telephone exchange As stated in Section 1.2 of this chapter, the FAX provides telephone facilities in all areas of the power station site. This site coverage was achieved in the past, prior to the introduction of FAX systems, by the use of office type intercom systems, supplemented by operational direct wire telephone systems. For about 40 years, until recently, all new CEGB power stations were equipped with an electromechanical PAX to provide automatic dialling of all site telephones. Most were of the Strowger type, Strowger being the name of the inventor of the first automatic telephone exchange which used a 'step by step' method of connecting telephone lines under the control of a telephone dial. Strowger systems were used almost exclusively, until recently, throughout the British public switched telephone network (PSTN). In later years, a small number of PAXs used in power stations were of the electromechanical crossbar type which used a form of common control switching. Both types are being replaced in power stations by stored programme control (SPC) telephone exchanges for both PAX and PABX requirements. The Strowger, crossbar and SPC type telephone exchanges are briefly described in the following subsections. 663
Chapter 8
Telecommunications 5.1.1 Strowger systems
The basic elements of a Strowger telephone exchange are the telephone extension line circuit, uniselector and selector. The arrangement of the elements used for a telephone call between two telephone extensions on a 100-line telephone exchange is shown on Fig 8.10 and is briefly described as follows: • Handset of calling felephone is lifted and operates its discrete line circuit in the PAX which then operates its discrete uniseleetor. • The wipers of the uniseleetor rotate to find the first unused selector circuit. Dialling tone is then returned to the calling telephone. • The first digit is dialled and the wipers of the selector step vertically to a position determined by the digit dialled. • The second digit is dialled and the selector wipers rotate into a horizontal bank of contacts coming to rest on contacts determined by the digit dialled. The contacts are associated with the called telephone. • The selector then transmits ringing current to ring the bell of the called telephone via the wipers of the selector and also returns a ringing tone to the calling telephone. • When the called telephone answers, the lines of the called telephone and calling telephone are connected via wipers of the uniselector and the selector, speech is then possible between the two telephones.
The Strowger system relies on the operation of complex electromechanical equipment which requires regular maintenance by skilled maintenance staff. 5.1.2 Crossbar systems
The crossbar system is more complex than the Strowge r system. The uniseleetor and selector functions of the Strowger system are performed by crossbars. Each crossbar unit comprises a matrix of contacts which are operated by levers (or fingers) to route circuits for speech and control through the telephone exchange. The mechanical movement of the equipment parts is small compared with that of the Strowger system and there is a reduction in the amount of wear and readjustment, so the maintenance requirement of a crossbar system is much less than that of an equivalent Strowger system. However, the complexity of the crossbar system requires skilled staff to diagnose and repair faults. 5.1.3 Stored programme control (SPC) systems
The SPC telephone exchange is now specified for PAX and PABX requirements at new power stations, and is also specified when replacement of Strowger and crossbar PAXs and PABXs at existing power stations is necessary. The SPC telephone exchange has few moving parts and a low maintenance requirement. Most faults can be rectified by relatively unskilled staff. Indeed, many problems are rectified by integral self-diagnostic equip-
STROWGER TELEPHONE EXCHANGE
SELECTOR
UNISELECTOR
fl. CALLING PAX TELEPHONE
LINE CIRCUIT
I ._L %
CALLED PAX TELEPHONE
OTHER SELECTORS
it
\a_
SELECTOR
FiCi. 8.10 Elements of a basic Strowger telephone exchange
664
Private automatic branch exchange (PABX) t which checks the operation of the telephone en exchange to identify the particular part which is faulty and then reconfigures the exchange to replace or by-pass he faulty area. Ft is also possible for diagnostic and reconfiguration operations to be carried out from manually-operated interrocration equipment at a remote location. The interrouation and corrective action is carried out after king a telephone call to the test number of the ma [elephone exchange which connects the remote interrogation equipment to the telephone exchange interro9tion circuit. The basic elements of the SPC telephone exchange are the telephone extension line circuit, electronic switch and the computer (central processor unit (CPU) and processor memory). The arrangement of equipment elements used for a call between two telephone extensions is shown on Fig 8.11 and is briefly described below: • Handset of calling telephone is lifted. The extension line circuit detects this and alerts the CPU which sends a dialling tone to the calling telephone. • The calling telephone dials digits, which the line circuit decoder passes to the CPU. The CPU disconnects the dialling tone after the first digit. • As the digits are received by the CPU it checks that the number is valid. If the digits are valid, the CPU sends ringing current to the bell of the called telephone and also a ringing tone to the calling telephone. • When the called telephone answers, the line circuit associated with the called telephone alerts the CPU, which then disconnects the ringing current and ringing tone and routes the telephone circuits through the electronic switch: the telephone conversation may then commence. The common equipment elements, e.g., CPU and processor memory, of the telephone exchange are duplicated and have facilities for automatic changeover in
TELE1-ONE EXCHANGE
N IJ IT :-RC E
_ ELECTRONIC SIMTCR LINE CIRCUIT
CALLED FAX TELEPHONE
COMPUTER
the event of failure, to minimise complete failure of the exchange. Many sophisticated facilities are available on the SPC exchange, only some of which are of use on a power station PAX. The more useful facilities are as follows: • 'Ring back when free' (automatic ring back of a calling telephone when a previously-called engaged telephone becomes free). • Three party conference (three telephones in speech contact). • Transfer of calls to another telephone. • 'Pick-up groups' which enables a single telephone to answer incoming calls to telephones in the same pickup group by dialling an abbreviated code.
6 Private automatic branch exchange ( PABX) The PABX provides automatic telephone facilities between locations within the power station and from nominated power station locations to the BT public switched telephone network (PSTN). Prior to the adoption of PABXs for power station use, the service was provided by a private manual branch exchange (PMBX) based on a manually-operated telephone switchboard. The telephone operator provided the required connection by using two flexible circuit cords (connected to a common bridging circuit) which were plugged into sockets wired to the lines of the PABX telephones or BT exchange lines for telephone conversations between PMBX telephones, or between a PMBX telephone and an exchange line. The PABXs currently specified for new power stations are SPC telephone exchanges, similar to that described in Section 5.1.3 of this chapter. The PABX is located in the station administration building, which is the area of the power station where the majority of PABX telephone users are located. The PABX is housed in its own equipment room, whilst the telephone operator's console associated with the PABX is located in the reception area of the station administration building. The receptionist provides telephone operator services in addition to reception duties. For a typical 2000 MW power station, the PABX normally has facilities for approximately 20 exchange lines and 250 telephone extensions. To provide a degree of diversity to enable a service to be maintained during possible failures of the PABX and/or BT exchange lines, the exchange lines will normally be arranged as follows: 13 Directory listed exchange lines 6 Ex-directory exchange lines 1 Ex-directory, out-of-area exchange line
Fig. 8.11 Elements of a basic stored programme control telephone exchange
The directory listed exchange lines have one common number listed In the BT local telephone directory, the 665
Telecommunications number normally dialled for the power station. On dialling the number, the BT exchange hunts for any one of the thirteen exchange lines to the station PABX which is not in use. The ex-directory exchange lines enable priority incoming, calls to be received by the PABX at all times from CEGB personnel requiring access to the station PABX from the BT PSTN, including occasions when the directory listed exchange lines are all in use or Faulty. Should the local BT telephone exchange fail, then a restricted service is available via the ex-directory out-of-area exchange line, which is connected to another BT telephone exchange, preferably in another town. Outgoing calls, originated from PABX extensions having direct access to the BT PSTN, will first have access to the ex-directory lines and then to the directory listed exchange lines, the directory listed exchange lines being kept available for incoming calls from toe BT PSTN. During normal conditions, the ex-directory nit-ofarea line is only available for calls made via the station telephone operator, The PABX will be powered from a battery-backed 48 V DC supply giving a minimum of seven hours standby should the mains supply fail to the associated 48 V DC charger. The PABX will have a dual processor to ensure operation should one processor fail. Should the PABX fail completely, then the exchange lines are automatically, or manually, connected directly to nominated telephones to provide a minimum service for incoming and outgoing telephone calls via the BT PSTN. A limited number of power station locations including the central control room (CCR), the station gatehouse (used by security personnel), the power station manager's office and the charge engineer's office are provided with telephones having direct access to the PSTN independent of the PABX. These telephones are designated direct exchange line (DEL) telephones.
6.1
General facilities
The PABX will include present SPC telephone facilities as follows: • Extension transfer of telephone calls. • Conference facilities. • Ring 'back when free. • Operator recall. • Group pick-up. • Abbreviated dialling. The PABX is chosen from a CEGB approved list which includes PABXs approved by the Department or Trade and Industry (DTI) for connection to the BT PSTN, 666
Chapter 8 which have also satisfied the CEGB tests and criteria for use in power stations.
6.2 Night service facilities Outside normal working hours, night service facilities for transferring incoming BT PSTN calls to the required PABX telephone extensions are provided from a PABX telephone extension on the CCR supervisor's desk. The night service facility is automatically transferred to a PABX telephone in the Gatehouse if the incoming call is unanswered at the supervisor's desk.
7 Paging systems 7.1 Lights and sounders The paging of power station roving staff from the PABX, PAX and fixed locations has for a long time been recognised as a useful facility. Before the 1950s various methods of staff location were used, one method was the use of combinations of flashing and/or coloured lights, another method being the operation of sounders to a repeated morse code signal. These systems required high levels of maintenance and were ineffective in noisy areas.
7.2 Inductive loop paging systems During the 1950s, an inductive loop paging system controlled from manual controllers was developed which operated by magnetic induction from a wire loop antenna. This antenna comprised a single-wire looped around a building or buildings with both ends of the loop being connected to the paging transmitter. For a large building or complex, the antenna sometimes comprised a number of loops to obtain the required cover. At a power station a number of antenna loops were necessary and a series/parallel arrangement of the individual loops was used to optimise the area of cover. The signals transmitted by the system antenna were in the frequency range 200-4000 Hz. The pocket pagers carried by mobile staff received the signals and emitted an audible tone if the pager received its unique identity signal. During 1961, a commercial inductive loop paging system manually-operated from a controller was installed at Uskmouth Power Station. The controller, which incorporated pager coding pushbuttons, was connected by cable to the main coding and transmitting equipment. An equipment was developed for the CEGB by one of the authors (F. Ashurst) to enable this paging system to be operated from any power station PAX telephone. At the time, this was a unique method of operation. The method of operation from any PAX telephone required the dialling of a single-digit paging system
Paging systems de, followed by a two-digit code for the required pager. The paged person dialled the common paging answering code from any PAX telephone to :pcak co the caller. Operation of the paging signal from the manual controller produced a different sound from the pocket pager to indicate to the paged person the need to call the telephone number of the manual controller instead of the common paging system answering code on the PAX. The First Aid Team or Fire Team could also be called from a special paging telephone in the power station CCR and multi-access to the special paging telephone ,\ as available to the Teams when they called the Team paging answering code from any power station PAX access co
telephone. One major problem associated with the inductive loop paging system was the occasional severing of the anienna loops which were routed via many of the buildings of the power station, resulting in a partial loss of cover.
The component parts are: • Central control equipment. • Manual controllers. • Transmitters and antennas. • Pocket paging receivers (pagers). 7.3.2 Central control equipment
The central control equipment in new power stations is usually mounted in a cubicle located in the NITR. This provides good access to the PAX which is also located in the MTR. Also mounted in the cubicle is a test manual controller used for operating, testing and programming the radio paging system. The cubicle is the focal point of the system and cables radiate from the cubicle to a secure AC power supply, the PAX, the other manual controllers and the dispersed fixed station transmitters. 7.3.3 Manual controllers
7.3 Radio paging systems Radio paging systems have replaced all other types of paging system in CEGB power stations. Most radio paging systems can be operated from manual controllers and from the power station PAX and PABX telephone systems, in a way similar to that of the inductive loop paging system. Present day radio paging systems provide an alerting signal and a simple numeric or alphanumeric information display. The radio paging systems currently use a group of channels in the 26, 27 and 49 MHz band of VHF radio channels which are available at present for the specific use of radio paging. These channels are not exclusive to CEGB but are also available for other commercial users. The licensing and allocation of the paging channels is controlled by the DTI who specify the conditions under which the system will operate. Each system it pplier is allocated a group of frequencies for use throughout the UK. The channel allocated by the supplier is selected so that mutual interference with other radio paging systems in the area of cover is minimised. The permitted maximum transmitted output and height of the antenna(s) are also specified to minimise mutual interference. However, the multi-use of the same paging channel in the area of cover will not necessarily cause interference as the coding of the signals transmitted on a common paging channel provides an additional safeguard to minimise the receipt of incorrect information by a paged person. 7.3.1 Component parts of a non-speech radio Paging system
It is CEGB policy to use non-speech radio paging s stems in power stations, for reasons which will be explained later.
Three manual controllers are usually provided for each radio paging system, as follows: • Test and programming controller fitted in the central control equipment cubicle (MTR). • Supervisor's desk, central control room (CCR). • Power station telephone operator and receptionist desk. The supervisor's desk and power station telephone operator's manual controllers have the following facilities, which are not available to the caller initiating a paging call via the PAX or PABX: • Individual call of all power station pagers with distinctive bleeping or vibrating of the pager to indicate a call from the CCR or the telephone operator. • Group call of members of operations or emergency teams, i.e., Fire, First Aid or Security. The pagers of the team members will also receive individual paging calls when their discrete number is called. If a pager is faulty, the user will be provided with a replacement pager. The replacement pager, however, operates on a different calling code to the user's normal pager. To enable the user to be called when his published number is dialled on the PAX, or called from a manual controller, it is necessary to programme the central control equipment with this information so that calls can be automatically sent to to the replacement pager. This may be accomplished from any of the manual controllers, if not barred, or from the test and programming controller. 7.3.4 Transmitters and antennas
A single transmitter with one or more antennas may be sufficient to provide paging signals in all areas of 667
Telecommunications a small power station, but large power stations, and particularly nuclear power stations, require a number of synchronised transmitters having multiple antennas with associated radiating cables. The transmitters are synchronised to prevent interaction of signals from two transmitters having radio cover which overlap in some power station areas. The synchronising is accomplished by frequency-di\ iding, the main transmitter radio signal and transmitting the lov, frequency derivative via telephone cable pairs to each of the associated slave radio paging transmitters where the signal is multiplied back to the original frequency, thus producing a synchronised transmitter output. The siting of the transmitters and associated antennas requires a detailed study of the power station main building and outbuildings including the cooling water (CW) pumphouse (much of which may be underground), coal plant (if a coal-fired power station) and the reactor area (if a nuclear power station). Particular attention is needed for the power station basement area. A close examination of the power station working areas or, if a new power station, a detailed examination of its layout, is necessary to determine the location of antennas to provide maximum radio paging cover. In underground locations and corridors, it may be necessary to supplement the antennas with 'radiating cable' (sometimes called 'leaky feeder') which provides a low power leakage of transmitted signal along its length to enhance the signal in areas of poor reception. Judicious routing through areas of poor reception of the radiating cables connecting remote antennas to the associated transmitters, will enhance the cover along their routes. Alternatively, radiating cable provided for radiating purposes only but having an electrical connection to the transmitter output signal, will also enhance the paging signal in difficult areas of the power station. Modern pagers are small compact devices which fit in a breast pocket. The calling signal operates any or all of the following alerting modes; audible tone, lamp or vibrator and also the numeric or alphanumeric displays. The power supply is provided by dry or rechargeable batteries. Calling the pager from one of the manual controllers or from a PAX telephone will operate the alerting devices of the pager, giving a distinctive alert to indicate the type of call, i.e., group call or individual call. The visual display will instruct the paged person to, for example, ring the manual controller, his emergency control (if the paged person is a member of an emergency team), or to call back a PAX telephone number. [f it is not convenient to ring back the originator of the page, it may be delayed at the discretion of the paged person. The pager will also store a number of paged messages which may be displayed retrospectively. To call a pager from a PAX telephone, the caller dials the paging system access code, followed by the unique code of the paged person, and then the PAX extension number for the paged person to call back. 668
Chapter 8 7.3.5 Direct speech
A 'paged person receive speech' channel is available as an optional extra on contemporary radio paging systems to enable the caller to transmit a verbal message to a paged person or group of persons. There is also a further optional enhancement to provide return speech from the paged person to the caller. These options are rarely specified for CEGB power stations, the use of alphanumeric displayed information on the paged receiver being preferred. The display gives the paged person unambiguous instructions of the action required and also the option of calling the initiator of the page or delaying this until a more convenient time. The provision of the received speech facility to a paged person would require a higher standard of reception throughout the power station areas, necessitating a larger number of fixed station transmitters. The provision of transmitted speech from the paged person would also require a large number of fixed station receivers to be positioned in strategic locations throughout the site. It is CEGB policy to provide roving station personnel who need direct speech communication with a handportable radiotelephone operating on the power station radio system. 7.3.6 Use of paging systems
It is the policy of some power station managers to issue most of the staff with a pocket pager which, for a large station, could be 400 or more. This enables all staff to be contacted wherever they are on site. Other power station managers restrict the issue of pagers to roving personnel; operations, maintenance, security and emergency team staff.
8 Radio systems
8.1 Introduction Radio systems form part of the telecommunication infrastructure at a power station. They are provided both to supplement and as an alternative to the telephone systems, i.e., radiotelephone systems and also for non-speech communication purposes, viz, crane radio control and anticollision systems. The increasing use of automatic control for power station plant has resulted in greater centralisation of the operational control and monitoring of the plant, and in a significant reduction in permanently manned, distributed control centres. This has reduced operations staff numbers and permitted greater flexibility and mobility in work patterns. The use of radio enables speech communication to be established with the mobile staff. As has already been mentioned, modern power stations have a central control room (CCR) from which the operation of the power station is monitored and
Radio systems -Introlied. Work carried out by staff involved in the dav-to-daY operation of the power station is controlled c
CCR. ; rout the Fmcr,,encies are dealt . with by the CCR staff, who , tcquire communication between the CCR and fire, id or damage assessment teams and the off-site
a tool to improve speech communications, • The need for a reliable and clear speech communication medium to enable staff to be instructed accurately to carry out operations on power station plant and machinery.
a
einer,lency services. ot" the most useful means of communication CCR and roving operations staff is by :,e[0,een the Ro%.ir.q staff are provided with a handportable r3di0teieph0ne (handportable) and each control desk in CCR is fitted with a radio system controller. Staff • handportables are also able to communicate with cdh other using the radio system. Additionally, radio ,[eins are used for other duties which involve com,y munication between other control centres and mobile e.g., between the maintenance works-control oflice and maintenance staff. Radio in nuclear power ,:alions is extensively used for similar applications as as for the special requirements of health physics and use during nuclear emergency activities. a:on it oring
8.2 Radiotelephony systems I he radiotelephone systems used in power stations are
1 , a.sed on commercially available private mobile radio (1 , \IR) equipment. PMR equipment is primarily de-
i ned for use with wide area mobile radio schemes. I hese comprise a central fixed station housing a highntmered transmitter and a sensitive receiver, a fixed oion antenna mounted on a mast located at a high point central to the required reception area and vehiclemounted mobile radios (vehicle mobiles). The fixed qation is usually connected by land lines to a remote control unit (controller). This arrangement is suitable for off-site communications, e.g., emergency communications between the rtmer station and the associated grid control centre ■%hcn other telecommunication links have failed. However, the standard type of PMR system must ! , c adapted to provide on-site radio cover inside power ':it ion buildings, which contain thick, reinforced con.. rete walls, floors and ceilings, large fabricated steel plant items, underground plant rooms and labyrinths ol cable ways and pipework galleries. None of these dre ideal places for radio signal propagation. . Die design constraints on the use of PMR systems in power stations can be summarised as follows: • (1 restriction of the field strength transmitted by handportables to reduce the effect of radio frequency
interference (RFI) on sensitive electronic control and instrumentation (C and I) equipment. • The hot,
• •
humid and dirty environment.
The harsh electromagnetic environment. The need for simple control units (controllers) in control rooms for operation by staff not employed as professional radio operators, but using radio as
In order to achieve a suitable radio system, accepting these constraints, it is therefore necessary to adapt the standard PMR equipment for use in power stations.
The radio systems used for power stations have developed from the use of a single remote control unit (controller) located in the CCR and cabled to a fixed station (transceiver) located in the plant area close to the antenna. The antenna has usually been mounted on the roof of the highest building, e.g., turbine hall/ boiler house or the mechanical annexe situated between the turbine hall and boiler house. This arrangement had to be supplemented by relatively high-powered handportables in order to provide adequate radio cover in all but the smaller power stations. As power station buildings have become larger and more complex, and the constraint on the power output of handportables has increased (in order to avoid RH to control and instrumentation equipment), so the radio system has had to become more sophisticated. The handportable RF power output has been reduced to 0.5 W into the antenna instead of art effective radiated power (ERP) of 0.5 W. The definition of an ERP of 0.5 W is the power radiated from a half-wave dipole antenna when 0.5 W is connected to it. As handportable antenna gains vary from —3 dB to — 10 dB when compared with a dipole antenna, the radiated power has been reduced to between 0.25 W and 0.05 W ERP. In order to compensate for these reductions, the antenna arrangements of the fixed stations have become more complex. The antenna systems comprise internal and external antennas supplemented by radiating cable (leaky feeder) in confined areas, e.g., basements, tunnels, corridors and CW pumphouses. In addition, distributed fixed station arrangements are used in medium and large power stations. The arrangements comprise fixed transmitters and receivers located at different plant areas adjacent to the antenna systems required to provide radio cover of the area. Prior to the availability of synchronising systems for transmitters and voting systems for receivers (which allowed automatic selection of the best received signal), the use of distributed fixed stations required each to operate on a different frequency. This was necessary to prevent interference at the receiving mobile. The interference was most acute when the two received signals were of the same frequency and field strength, and was due to the rapid cancellations taking place in the combined received signal as the two varied in phase with each other. As more radio frequency channels were required to carry the communications traffic, it became necessary 669
Telecommunications
Chapter 8
to adopt new techniques to improve the efficient use of the channels available. One technique was to use quasi-synchronous operation of the fixed station transmitters to allow the same channel to be used simultaneously at all fixed stations. This provided full cover of the station by each channel and enabled two handportables operating via two different fixed stations to use one channel instead of two, as was previously the case. This technique also dispensed with the need for handportable users to remember which channel had to be used in different areas of the power station. Channels were allocated to the main functional groups, e.g., operations and maintenance, for use throughout the power station. Details of quasi-synchronous operation and the associated receiver voting system are given later in this section. The latest development being evaluated by the CEGB is the use of radio channel trunking techniques. A trunked radio system uses the frequency agility of the modern synthesised transmitters and receivers available for handportable and mobile radios to enable them to be remotely switched to a channel. One of a group of radio channels is used as a control channel in conjunction with a microprocesser-based control equipment (CEQ). The CEQ sets up calls between mobiles, controllers or telephones connected to the system and allocates each call to a traffic channel (the name given to the remainder of the channels in the group). Each call is allocated a traffic channel sequentially on a first come first served basis. Once a call has been allocated a traffic channel the CEQ and control channel are free to deal with the next call. This type of system makes more efficient use of the radio channels and enables sufficient channels to be provided to allow a large number of !ow traffic users to be given radio facilities without the need for them to be skilled at radio procedures to make efficient use of a common channel. The trunked radio system also provides a number of additional improvements and facilities which are described in detail in Section 8.2.5 of this chapter on UHF systems. 8.2.1 Radio frequency bands used by RMR systems
PMR equipment is manufactured to operate in the VHF and UHF bands of the radio frequency spectrum. The two bands cover the following frequencies: Band
Freqi4eney
8
30-300 MU-1z
9
300-3000 MHz
Metric subdivision
Designation
Metric
VHF
Decimetric waves
UHF
Band 8 contains the following three PMR frequency bands: 670
LOW BAND (12.5 kHz spacing)
NIID BAND (12.5 kHz spacing)
HIGH BAND
71.50-72.80 76.95-78.00
Mobile transmit Two-frequency simplex
85.00- 86.30 86.95-88.00
Fixed station transmit Two-frequency simpl ex
86.30-86.70
Single-frequency simplex
105.00-108.00
Mobile transmit Two-frequency simplex
13800-141.00
Fixed station transrnit Tss n-frequency simplex
165.05-168.25
Fixed transmit Two-frequency simplex
169.85-173,05
Mobile transmit Two-frequency simplex
168.95-169.85
Single-frequency simplex
(12.5 kHz spacing)
Band 9 contains the following PMR frequency bands: UHF BAND
453.00-454.00 Fixed station transmit 456.00 -457.00 Two-frequency simplex 459.50-460.50 461.50-462.50
Mobile transmit Two-frequency simplex
Section 8.7.1 of this chapter gives an explanation of single-frequency and two-frequency simplex operation. 8.2.2 Comparison of VHF and UHF systems
The antennas used for PMR systems operating in the VHF and UHF frequency bands are similar. These are derivatives of the standard half-wave dipole. The actual antennas used will be dealt with in more detail later. However, it is worth noting at this point that the receiving area of an antenna determines the power received from a radiating signal, which is measured in watts per square metre (see Section 8.5.1 of this chapter). The area of a receiving antenna is proportional to the square of the wavelength of the radiating signal. Therefore a half-wave dipole is more effective at VHF than at UHF. This also applies to those antennas that are derived from the half-wave dipole. This is one reason for using VHF off-site and UHF for on-site telecommunications in a power station, where there is a requirement to confine the radio cover to the site and immediate area around the site, thus allowing the re-use of the UHF frequency channel elsewhere in the country. VHF PMR equipment is therefore used for telecommunications between the power station and mobile or fixed stations up to approximately 30 km away, depending on the height of the transmitting antenna and the type of surrounding terrain, while UHF PMR equipment is used for on-site radio systems, i.e., up to approximately 8 km from the power station. With careful design, it has proved possible to repeat UHF frequency channels at minimum distances of 1216 km and thus make economic use of the UHF radio spectrum. Detailed design requirements to achieve this
Radio systems minimum distance are given in the antenna system Liesi,n Section 8.6 of this chapter. 8.2.3 Allocation of radio channels 1,1c allocation of radio frequency channels for use by CEGB is not carried out directly by the Radio unications Division of the Department of Trade 1ndustr} (DTI). The D has allocated a group of the exclusive use of the fuel and power quencies for : dustries. This group of frequencies is administered il alf of the member industries by a Joint Radio on behalf ittee (J RC). The JRC considers all applications comm (or radio licences received from the member organisaon, and allocates radio channels with the prime objecavoiding mutual interference between systems. , i% e of The main method adopted by the JRC to achieve is to allocate channels to each member organisa:ion, using spatial diversity to reduce the possibility of _nterference between locations allocated the use of the frequencies. This is particularly the case for local radio schemes using the UHF band. rca Sections 8.2.4 and 8.2.5 of this chapter show the present groups of frequencies used in power stations and he proposed changes in the UHF group of frequencies. These changes have become necessary followfl‘.: the 1979 World Administrative Radio Conference i wA RC) of the International Telecommunications t_ [l i on where it was agreed to adopt 12.5 kHz channel spacing instead of 25 kHz, by taking advantage of modern developments in radio manufacture. This will re,ult in the more efficient use of the radio frequency spccirum. 8.2.4 VHF systems used in power stations I lic frequencies used for power station VHF systems
The Low band VHF systems are all single-frequency si mplex and are used for off-site radio communications between fixed desk-mounted or table-top controllers connected by multipair cable to fixed stations housing radio transmitters and receivers. The fixed stations are connected by coaxial cable to external antennas, usually mounted at a conveniently high position art the roof of one of the power station buildings. The VHF Grid Emergency System provides communications between the power station and remote radio fixed stations located at other power stations, the Grid Control Centre, manned substations or switching stations situated within a radius of 35 km of the power station. The VHF nuclear emergency systems provide radio communications within a radius of 35 km of a nuclear power station. During a nuclear emergency, they provide communications between the power station incident control room, health physics monitoring teams, off-site support centres (OSCs) and nuclear emergency organisations. The VHF nuclear emergency systems are also used for routine communications between the power station and health physics monitoring teams and in-transit nuclear fuel flask vehicles. The Low band VHF channels are also used for an emergency handportable to handportable communications system for on-site emergency purposes at nuclear power stations. The Mid and High band single-frequency channels are used for handportable to handportable communication systems for commissioning, maintenance and emergency purposes. The handportable systems supplement the UHF systems and also provide limited communications in the event of the failure of the UHF systems.
arc:
8.2.5 UHF systems used in power stations
I OU BAND 5555
MHz
Grid emergency system channel Single-frequency simplex
6- 5
MHz
Nuclear emergency system channel I Single-frequency simplex
MHz
Nuclear emergency system channel 2 Single-frequency simplex
BAAD -
1n5. 687
mtt z
117 7 .13125 MHz
Handportable to handportable Maintenance/commissioning system Single-frequency simplex Handportable to handportable Maintenance/commissioning system Single-frequency simplex
BAND
164.050
NI Hz
Handportable to handportable !Maintenance/commissioning system Single-frequency simplex
Changes to the Low and Mid band channels are under onsideration at present.
c
The frequencies used for power station UHF systems are in the process of change (1988). The existing twelve 25 kHz spaced channels are being replaced by twentyfour 12.5 kHz spaced channels. The existing group of twelve 25 kHz spaced channels is: Channel No
Transmitted frequencies
Fixed station (MHz)
Mobile (MHz)
21A
456.050
461.550
22
456.075
461.575
22A
456.100
461.600
In similar 0.025 steps to 27
456.325
461.825
The proposed new group of twenty-four 12.5 kHz spaced channels is: 671
Chapt er a
Telecommunications Channel No
1283 to 1306
Transmitted frequencies Fixed station (MHz) Mobile (MHz) 456.0375
461.5375
in 0.0125 steps to in 0.0125 steps to 456.3250
461.8250
UHF systems used for on-site radiotelephone communications are based on conventional PMR systems which use manual selection of the radio channel by a mobile or handportable for speech communications. Automatic allocation of one of a group of radio channels, as used in trunked radio systems, is at present being evaluated by the CEGB. The conventional UHF systems used for on-site radio communications comprise desk-mounted or table-top controllers, fixed stations containing the base station radio transmitters and receivers (for each of the radio channels used by the power station) and mobile radios. The mobile radios include handportable radiotelephones and radiotelephones mounted in vehicles. The complexity of the controllers will depend on the overall complexity of the radio system and the ability of the radio contractor to supply customised simplified controllers instead of his standard model. The controllers are connected to the fixed stations by multipair cables. In modern power stations the cables have short-time fireproof insulation material to improve
the security of the radio systems. Single and multichannel controllers are provided as necessary. A single-channel controller has access to one radio channel only, whereas a multichannel controller has access to a number or all of the channels. The latest controllers have a programming facility, which enables the number of channels accessible to the controller to be pre-programmed, as required by the customer. The fixed stations are located within the plant areas of the power station, close to the associated antenna systems. The number of fixed station locations is dependent on the number of antenna systems required to provide good radio cover of the power station. The number of fixed station transmitter/receivers is dependent on the number of radio frequency channels allocated to the power station. This is based on the predicted speech traffic requirements for operation, maintenance and emergency purposes. To avoid interference between the signals transmitted simultaneously from a number of distributed fixed stations, it is necessary to use one or a combination of the following: (a) The allocation of different radio frequency channels to each fixed station. (b) To repeat the use of the same radio frequency channel(s) only if there is no possibility of an overlap of the radio cover between any two of the fixed stations. 672
(c) The use of quasi-synchronous or synchrono us operation of the transmitters which use the same radio frequency. (d) The use of a best signal received voting arrange_ ment for receivers operating on the same radio frequency. (e) The use of dynamic sharing of the radio channels between fixed station locations so that each has access to all channels, but only those channels not in use at other locations being used at any one time. Alternatives (c) to (e) require a common control equipment (CEQ) to which each fixed station and controller is connected. The CEQ carries out the receiver voting and dynamic sharing operations for the whole system. The present practice is to provide a single fixed station location for small power stations and distributed fixed stations for medium and large power stations. Each fixed station is connected to a dedicated antenna system. The antenna systems comprise a combination of internal and external antennas, supplemented on larger power stations by radiating coaxial cables (leaky feeders). The complexity of the antenna system depends on the level of difficulty experienced in providing good radio cover throughout the station. The design objective is to obtain a level of radio cover better than a minimum sensitivity signal to noise ratio of 15 dB SINAD. SINAD
is the acronym for Signal Noise And Distortion. Signal to noise ratio in dB SINAD = 10 log
S+N+D N +D
where S = signal power N = noise power and D = distortion power. For a modern receiver, a sensitivity of 15 dB SINAD would be equivalent to a signal of approximately 1 AV pd at the receiver input.
The mobile radios include up to four radiotelephone units mounted in vehicles, e.g., ambulance, fire tender and four-wheel drive vehicles, and up to sixty handportable radiotelephone units carried by staff working in the power station. The mobiles can be single or multichannel radios. The multi-channel mobiles, which can be switched to the channel on which the user wishes to operate, are usually provided for those power stations which are allocated multiple radio channels, e.g., up to five. The number of channels allocated to a power station is dependent on the size of the station and the predicted radio communications speech traffic. The radio requirements for the operations function of a station having two turbine-generator units could be satisfied by one channel but a six - unit station could need at least three channels for operational purposes.
Radio systems The present JRC agreement allows large stations to e a maximum of five radio channels. It is expected h av that this could increase to eight following the change ,012.5 kHz channel spacing to be completed by the early 1990s, The aetual number of channels allocated power station will depend on the predicted traffic a r...otaireinents for normal operations, maintenance, cornand emergency purposes. :no n services turbine-unerator unit station, in addition to operations channel, would have a channel allocated to maintenance. large six turbine-generator unit station would have fi%re radio channels typically allocated to five radio . ■ ;terns as follows: • Operations system for Units I and 2. • Operations system for Units 3 and 4. • Operations system for Units 5 and 6. • Maintenance/emergency system. • Common services system. The common services system would include the followin , systems sharing the same radio channel: • Security system. • Ambulance, fire and first aid system. • Site transport system. The operations systems would include the following vstems sharing the same radio channels: • Fuel handling system. • Waste disposal system, e.g., ash or spent nuclear F uel. • Crane speech communication system. Plant or site emergencies are initially dealt with by :lie operations staff in the CCR using the operations ], stern(s). For a prolonged emergency, e.g., in a nuclear station, control of the incident would be assumed by [he emergency control centre and the mobile staff insolved in dealing with the emergency would take over use of the maintenance or common services system. The operations system would then be released for its prime purpose, i.e., to be used by staff engaged in the operation of the plant unaffected by the incident. The method of informing the relevant staff to switch :0 the emergency channel will depend on the emergency procedures of a particular power station. The method ould be based on the use of one or other of the two Power station 'global' communication systems, i.e., i he siren and public address systems. The design bandwidth may limit the handportable to a maximum of three channels. When this is so, two groups of handportables have to be provided if, as is he case for a large power station, five channels are \.ailable for use. The two groups of handportables ,
would be provided with three channels each, one of which would be the common channel, to which all handportables could be switched in an emergency. The radio systems can also be provided with audio or sub-audio signalling systems for use with selective calling systems (SELCALL) and continuous tone calling signalling systems (CTCSS), respectkely, see Section 8.4.3 of this chapter. The SELCALL system enables an operator of a radio controller to use the keypad on the controller to call any individual mobile which has a SELCALL decoder fitted. On receiving the appropriate SELCALL code, the mobile receiver unmutes the audio output to the loudspeaker and allows a calling signal to be heard by the user. If the appropriate code is not received, the user is unaware that a call is in progress on the radio channel unless he deliberately unmutes the mobile by manually operating a SELCALL defeat switch. The SELCALL facility is usually provided on the operations systems in order to provide the CCR staff with a means of ensuring that the operator who is to be given an instruction is the correct operator for the work in progress. The CTCSS system consists of a sub-audible tone which is transmitted simultaneously with the radio frequency signal. All fixed station and mobile transmitters allocated to the radio channel carry the same CTCSS tone encoder and all the receivers the appropriate CTCSS decoder. Unless the radio frequency signal also includes the appropriate CTCSS tone, the receiver will not unmute the receiver audio circuit. Therefore, any calls on a radio channel shared with other organisations will only be heard if the correct CTCSS tone is present or the mobile is manually unmuted using a CTCSS defeat switch. The CTCSS system is used on the non-operational channels instead of SELCALL because these channels are used more frequently on talk-through, which requires the handportable to be unmuted. CTCSS will automatically unmute the handportable, whereas receipt of a SELCALL code initially unmutes the handportable which only stays unmuted for a preset time after receipt of the code or subsequent operation of the handportable transmitter (i.e., the press-to-talk 'PTT' switch). The CTCSS system reduces the irritation that often occurs when the radio channels are shared with other organisations. Both the SELCALL and CTCSS systems are useful where a power station has to share radio channels with an associated power station construction site or another separately-managed power station. Distributed fixed station systems
Distributed fixed station systems are used in modern power stations to provide good radio cover. As has been explained previously, distributed fixed station operation has become necessary for two main reasons: 673
Telecommunications • The increased size and complexity of the civil design of a modern power station. • The necessity to limit the RE output power of handportables to 0.5 W into the antenna to reduce the RFT to electronic control and instrumentation equipment. Each fixed station is located close to the associated antenna system which comprises a combination of inter;i al and external antennas and radiating cable (leaky feeder). The external antennas are mounted as low as possible commensurate with good radio cover of the site, which includes outlying buildings having no antenna system of their own. The internal antennas are mounted in the large open areas within the power station, e.g., turbine hall/boiler house and CW pumphouse. Radiating cable is used in confined areas, e.g., basements, tunnels and enclosed corridors. In order to prevent mutual interference between fixed stations, it is necessary to allocate different frequencies to each. This is not necessary for those fixed stations which serve a totally confined area. However, in modern power stations the radio cover from each fixed station is so complex that it is difficult to confine the area of cover. The disadvantages of using different frequencies at each fixed station are: • Mobile users need to remember which channel has to be selected for use in different areas of the power station. • Calls to mobiles require a polling facility to enable calls to be made from each fixed station transmitter in turn. This increases the call set-up time. • Calls between mobiles operating via different fixed stations require the use of two or more channels for a single conversation or conference between three or more mobiles. • A single emergency channel, to which all mobiles can be switched in order to monitor the emergency situation as it progresses, cannot be provided. In order to overcome these short-comings in the system, quasi-synchronous operation of the fixed station transmitters and voting of the associated receivers has been adopted. Quasi-synchronous operation of the transmitters allows the same channel frequency to be used at each fixed station. This provides full radio cover of the power station on all channels. The system uses high stability oscillators, permitting the channel frequency at each fixed station to be offtuned by one or two Hertz from each of the adjacent fixed stations. The effect of this arrangement is that a mobile which receives signals of similar field strength from two fixed stations will detect a beat frequency of one or two Hertz, but will not experience rapid 674
Chapter 8 fluctuations in signal due to phase cancellations. Theoretically the one or two Hertz beat frequency, bein g sub-audio, will not be heard by the users and therefore speech quality will not be impaired. In practice, in those areas having pronounced quasi-synchron ous effects, a background noise is detected which rises and falls in amplitude at a low frequency of one or two Hertz. This noise is produced by multipath signals arriving at the receiving antenna which vary in pha se , However, the effect does not normally detract from the intelligibility of the speech. On the rare occasions when intelligibility is affected, a small spatial movement by a handportabie user of one or two paces will result in a marked improvement in reception. This is because the points of poor and good reception tend to be located on a small-meshed matrix covering the affected area. Signals received at two or more fixed stations from the same mobile are compared in the CEQ, the best quality signal is then selected by a receiver voting system and connected to the receive bus of the CEQ. The CEQ bus is then connected to the cable from a controller or to a transmitter if the call is between mobiles. Whe re an area is adequately covered by the fixed station transmitter but not by the associated receiver due to the lower power output of the handportables, one or more distributed fixed station receivers can be provided to improve cover. An alternative to the use of quasi-synchronous transmitters is to use the frequency agility of synthesised transmitters and receivers in the mobile. The CEGB is evaluating trunked radio systems which make use of the synthesised mobiles and fixed stations now available. Trunked radio systems
Trunked radio systems use automatic allocation of one of a common group of radio channels to a mobile radiotelephone, directly wired controller or telephone each time a radio call is made. The system dispenses with the need to allocate each radio channel to a specific function, e.g., operations, maintenance or common services, and makes more efficient use of the radio channels available for a power station. Channels can be shared by adjacent power stations, or power station construction sites, which results in more efficient use of channels and makes more channels available to each management unit in times of emergency or abnormal operational activity. In order to share channels between adjacent power stations, or between a power station and an adjacent construction site, a data signalling link has to be provided between the CEQs of each of the radio systems. The link is used to indicate to each CEQ the channels in use at any one time. Automatic channel selection requires a change to the method of operating the mobile. In a conventional radio system the mobile user switches to the channel and uses a verbal call-sign or the name of the called
Radio systems party. The user of a directly wired controller connected /0 the CEQ adopts a similar procedure, or uses a keypad se,nd a selective calling code to initiate an alerting denal in the called mobile. In a trunked system the calling mobile has to request r ree ra dio channel. This is usually achieved by pressall request or send button on the keypad of a c :he 'nubile. No systems are being evaluated by the CEGB for in power stations and power station construction tt , e. sites:
which has been used on the Continent for • A system
a number of years which uses the Comite Consultatif International de Radio (CCIR) sequential single freency code (SSFC) signalling from fixed station to qu mobile and the Comite Consultatif International de Telegraphique et Telephonique (CCITT) dual tone multi-frequency (DTNIE) signalling from mobile to fixed station.
• A system which is based on the digital signalling system specified in the Ministry of Posts and Telecommunications specification MPTI327, 'A signalling Standard for Trunked Private Land Mobile Radio Systems' issued by the Radiocommunications Agency (RA) of the Department of Industry (DTI). The same signalling system is used in both directions of transmission between the fixed station and the mobile. In the CCIR/CCITT system, pressing the call request button results in the mobile seizing one of the group of trunked channels which is not transmitting a 'channel busy' signal. The microprocessor-controlled Common equipment (CEQ) of the system then carries out a 'handshake' procedure over this selected channel to Identify the mobile before returning a dial tone to he mobile. The handshake procedure consists of an identity (ID) code being sent to the mobile and an acknowledgement being returned to the CEQ. On reeek ing dial tone the caller then keys the code of the aIIed party on the keypad of the mobile. DTMF signals .issociated with each key pressed are sent over the ,hannel. This procedure is referred to as 'on-air call set-up'. The called party can be a mobile, telephone or controller directly wired to the CEQ, or a PAX/PABX elephone connected via interconnecting tie-circuits between the CEQ and the FAX or PABX. Calls from a directly wired telephone or controller, PAX or PABX telephone are carried out in a similar manner. On receipt of a call for a mobile, the CEQ transmits a calling signal via one of the free channels hich is being monitored by the quiescent mobiles. fhe calling signal contains a preamble signal to allow all quiescent mobiles to switch to the channel followed b> an ID of the called mobile. On receiving the correct ID, the mobile sends an acknowledgement signal back to the fixed station. At the same time the receiver of the handportable is unmuted and the acknowledgement
signal is heard at full volume in the handportable loudspeaker. When the acknowledgement signal is received by the CEQ, a ringing tone is sent to both the called and the calling party. The press-to-talk (PTT) button has to be depressed on the called mobile to answer the call. On receipt of the PTT signal, the CEQ removes the ringing tone. Normal speech communications can then take place. Should the called mobile not answer or be engaged on another call, the CEQ would send a 'number unobtainable' or a 'busy' tone to the calling party. In the MPTI327system, a fast frequency shift keying (FFSK) digital signalling system is used in both directions between the fixed station and the mobile. Two operational systems are available: • For large systems, e.g., a group of five or more channels, one of the channels is designated the control channel and all mobiles continually monitor this channel when in the quiescent state. The remaining channels are used as traffic channels to which mobiles are switched automatically by the CEQ (via the control channel) once a communications link has been established between a calling and called party. • For smaller systems, any one of the channels assumes the role of control channel until there are no other channels available for use as traffic channels. The control channel then assumes the function of a traffic channel after first acting as a control channel to set-up the communications link between the calling and called parties. The next channel which becomes free then assumes the role of control channel. During the period when all channels are busy, additional calls cannot be made with the exception of 'override' calls which are initiated by callers having a congestion override class of service facility. In the MPTI327 system the called party's ID is first entered into the memory of the mobile and the send button is pressed. The mobile then transmits a call request (RQS) message on the control channel. When the CEQ is free to handle another call the RQS is accepted and an acknowledge call request (AKQ) message is sent to the mobile. The mobile will next send the called party's ID which is stored in its memory. This process of storing the called party's ED before it is transmitted is referred to as `off-air call set-up'. The CEQ stores the ID and uses a look-up table held in memory to determine whether the called ED is a mobile, directly wired controller or telephone, FAX or PABX telephone. If the called ID belongs to a mobile the CEQ sends an 'Ahoy' (AHY) message via the control channel to all mobiles. If the mobile is busy or not available the CEQ will send a busy or number unobtainable tone to the calling party. If the called mobile receives the AHY message an AKQ message is returned via the control channel to the CEQ. The CEQ sends a 675
Telecommunications calling message to the mobile and a ringing tone to the calling party. On receipt of the calling message the mobile will emit an audible calling tone. The call is answered by pressing the PTT button on the mobile. On receiving the PTT signal, the CEQ removes the calling message and ringing tone and connects both parties to a common traffic channel. Speech communications can then proceed over the traffic channel while the control channel is free to handle subsequent calls. If the called ID belongs to a directly wired controller or telephone or to a PAX/PABX tie-circuit, the CEQ sets up a hard-wired path to the called party and rings the controller or telephone, or transmits the necessary dial pulses/DTIvIF signals over a PAX/PABX tiecircuit. On receipt of an answering signal from a directly wired controller or telephone, the CEQ would connect the parties to a common traffic channel. Alternatively, on completion of the dial pulses or DTMF signals over the PAX/PABX tie-circuit, the CEQ would connect the calling party and the tie-circuit to a common traffic channel. The MPT1327 system has the advantage of off-air call set-up and faster signalling speeds which make more efficient use of the radio channels. Both the CCIR/CCITT and the MPTI327 systems use timers to control the occupancy time of the traffic channels. Fixed timers are used to limit the occupancy to a customer-determined period, e.g., 2 min. When dynamic timing is provided, the fixed timers are overridden only when there is not a free traffic channel left on the system. This is another method of improving the efficient use of the radio channels. The timers that are normally incorporated in a system are as follows: • The dynamic timer which provides a warning signal approximately 10 s before clearing-down a communications channel. The dynamic timer is only activated when there is only one channel free on the system. This ensures a channel is available, or is made available, at worst after a period equivalent to the setting of the minimum fixed timer for emergency or priority calls made from a mobile or handportable. • A minimum fixed timer which is set to provide a minimum period for conversation, e.g., 60 seconds, before the dynamic timer is able to clear-down a channel. • A maximum fixed timer which is set to provide a maximum period for conversation to take place, e.g., 5 minutes, before a forced clear-down sequence is initiated. This timer would be over-ridden by the dynamic timer during periods of heavy traffic. • A channel activity timer is also provided which is initiated each time a PTT is operated on the channel. If a PTT operation is not detected in a preset time, e.g., 30 seconds, a warning signal is transmitted. 676
Chapter 8 If a PTT is operated then the timer is reset. If a PTT is not operated within approximately 10 seconds of hearing th ,.; warning signal a clear-down sequence is initiated. The use of microprocessor control in the CEQ of both systems enables sophisticated facilities to be provided. Examples of these are as follows: • Abbreviated keying — this enables the mobile to u se more easily-remembered one or two digit codes in place of frequently used or lengthy codes, e.g., calls to the CCR telephone or to telephones on the CEGB CT N. • Ring-back when free — this enables a calling party to request to be called when a busy party becomes available after a call is completed. • Group calls — this enables the CCR to call a group of mobiles, e.g., a fire team, by keying a common group code. • Emergency override — this enables mobiles or directly wired controllers/telephones with the necessary class-of-service to 'knockdown' an existing call of a lower class-of-service if all channels are engaged. Some of the facilities, e.g., abbreviated keying, can be used to simplify the operation of the mobile for those users not requiring the more sophisticated facilities. Both trunked systems have the following important features:
• Efficient use of the radio frequency channels which enables more traffic to be handled. • Confidentiality of radio conversations as controllers and mobiles are unable to select busy channels and monitor them. • Remote control units (controllers) can be replaced by directly wired telephones which simplify the procedures for accessing and using the system. This is more acceptable to control engineers who, in general, do not wish to be trained radio operators. • The users have the equivalent of a dedicated channel for each call on the system. This enables a large number of low-level traffic user groups to make use of radio whereas previously, because they were unable to have a dedicated channel, they opted out of using the system. The resulting integrated traffic requirements can be used to justify the allocation of more channels to the power station. • The use of datalinks between radio systems serving two or more adjacent power stations or between a partly commissioned power station and its adjacent construction site, enables a group of common channel frequencies to be shared. This provides a larger pool of channels which are available to any
Radio systems one of the sites during unusually busy periods, e.g., annual overhauls and site emergencies. • Direct dialling/keying between the radio and PAX/ • This creates an integrated telecommunicap . .\[3x. n for telephone and radio users. This lions ,, stel facility enables station staff to speak to remotely , , d specialist support engineers directly from 1
co
rlant INations.
8.3 Crane radio systems used in power stations to the PMR-derived radiotelephone systems, [11,idditiOD !here are a number of other radio systems used in a ramer station. These include LF systems and SHF imicroNA aye) systems used for crane control and antiollision systems. The two systems use the following .: rrequeney bands: Mud
Designation
Metric
frequency
subdivision
10 - 300 kHz
Kilometric
LF
waves
(low frequency)
3-30 G Hz
Centimetric waves
SHF (super high [regency)
8.3.1 Crane control systems
[here are three types of crane control system available, loss. frequency (LF) analogue systems, VHF or UHF dOtal systems, and combined LF and VHF or UHF.
Low frequency (LF) crane control systems LF crane control systems use frequencies in the 287-313 kHz band, which is shared with maritime radio navigation beacons. This system has been used for remote control of power station cranes since the 1960s. The use of LF provides a limited range facility to ensure that the transportable remote control transmitter unit cannot operate the crane from a distance greater than 100 m, so that the crane is always operated from a safe distance. Ideally the operator would be close to the load while operating the crane by radio control. This limited operating range is achieved because the radio field strength (electric field strength E (V/m) for a high impedance source, e.g., a dipole, or magnetic field strength H (A/m) for a low impedance source, e.g., a current loop) of an LF signal varies inversely as the cube of the distance for distances within a sixth of a wavelength of the transmitter, i.e., within the 'near-field region', which extends to a distance approximately equal to X/27r metres from the transmitting antenna where X is the wavelength of the RF signal. Figure 8.12 shows the graph of wave i mpedance against distance from source for both high and low impedance sources. For a typical system using a ferrite dipole having a gain of one with respect to a half-wavelength dipole antenna and for an RF signal of 300 kHz, the near field would extend to approximately 160 m from the antenna of the transportable transmitter.
5000 4000 3000 2000
WAVE IMPEDANCE.
HIGH I MPEDANCE FIELD 500
L
30. L 200
LOW I MPEDANCE FIELD
100 —
20
NEAR FIELD
FAR FIELD
OR INDUCTION FIELD
10 0.05
0.1
OR RADIATION FIELD 05
1 0
50
DISTANCE FROM SOURCE NORMALISED TO >. '2 n..m
Fu_.. 8.12 Radio wave impedance as a function of distance from the transmitting antenna 677
Telecommunications The LF crane control system used by the CEGB uses a multichannel, transportable transmitter and a crane-borne multichannel receiver. One channel, the safety channel, is allocated to providing the restricted range and all other signals received by the receiver have to lie inside a narrow amplitude window centred on the safety channel. Control signals comprise tinmodulated LF radio channels; in the simplest system one per control function, En order to reduce the size and weight of the battery required for the transportable transmitter, the RF output power is kept to a minimum, i.e., of the order of 60 mW. To compensate for the low RF output a sensitive receiver is mounted on the crane. The maximum sensitivity of the receiver is approximately 0.02 pV. The sensitivity is adjustable to provide the required operating range up to a maximum of 100 m. The amplitude window is approximately +6 dB either side of the safety channel received level and the frequency window is approximately ±25 I/4z of the nominal frequency of the channel. It was thought for many years that this narrow frequency/amplitude window and the use of the nearfield region of the radio frequency signal gave a high level of security from malfunction due to external interfering signals. Following two malfunctions, which were eventually discovered to be not wholly the fault of the radio system design, a detailed analysis identified weaknesses in the security of the system. The restricted range of the system depended on the receiver operating in the nearfield region of the transportable transmitter. However, this did not restrict the receiver to operating within the near-field region of interfering signals. Due to the high sensitivity of the receiver, it was found that it could respond to signals from high-powered transmitters located a number of kilometres away from the receiver, the signal having been attenuated to a level which was within the security frequency amplitude window. Initially, this was thought to happen at only one particular level of signal. Analysis showed that this was not so. As the transportable transmitter moves beyond the minimum operating distance from the receiving antenna to the maximum operating distance, the received level of the safety channel signal varies in proportion to the inverse of the cube of the distance. This results in a much wider amplitude window than was originally thought. It was also found that high levels of interfering signal having a frequency just outside the pass band could be attenuated by the narrow band crystal filters in the receiver to levels matching that of the safety channel signal. This would occur when the transportable transmitter was at some particular operating distance from the receiver. This could effectively increase the frequency window to a value approaching the full receiver bandwidth of approximately 3 kHz for single frequency interfering sources. 678
Chapter 8 The good safety record of the system had been mainly due to the limited number of users in the LF band and the monitoring of the frequency band usage by the supplier of the crane control system. The other main user of the band is the Trinity House, which uses the band for shore-based radio beacons. Unfortunately, many power stations are also built on coastal sites. The other limitation of LF systems is the increased LF pollution generated by modern industrial plant, viz., RF heating, welding and inverters. En locations with high LF pollution, an LF syste m can be rendered inoperable by LF noise causing the receiver automatic gain control to desensitise the receiver. This reduces the controlled range of the system below the minimum operating distance. For these reasons, the use of crane control relying solely on an LF system was discontinued for high category cranes, e.g., turbine hall, cooling water pumphouse and nuclear pile-cap cranes. However, there are a number of well tried, successful features of the LF system which are the result of good engineering design such as: • Limited operating range. • DC outputs from the receiver being derived directly from the RF received signals. • Emergency stop facility based on the loss of the RF signal. These features have been retained where possible by the CEGB as necessary requirements for any crane control system.
VHF or UHF crane control systems There are a number of VHF/UHF crane control systems available. These systems include the use of digital signalling, which gives a higher level of security than that obtained from the use of frequency-division multiplexing of unmodulated signals in the analogue LF system. One way of specifying the security of a digital code is to quote the 'Hamming distance' of the code. The term 'Hamming distance' is a concept used in assessing the checking ability of codes. It is the measure of the number of sequential positions by which the correct and incorrect code combinations differ. A code with a Hamming distance of d is capable of detecting all combinations of (d — I) or fewer errors. Thus a code that only required one bit to change, for example, a 1 to a 0 to make it an acceptable but incorrect code, has a Hamming distance of 1 and is not capable of detecting any errors, i.e., d I = 0. The systems available at the present time have Hamming distances in excess of 4, and more sophisticated systems are bound to follow the trends in data systems, which include error correction as well as error detection facilities. The present crane control systems comprise one way systems similar to the LF system, i.e., a crane-borne
Radio systems ver and a transportable control transmitter. Thereis no communication path from the crane the direction of the transportable controller to allow in orifirtnatory checks to be carried out between the ,: rane receiver and the controller. ‘: The systcms arc microprocessor-based which has „ i ited in the de ■.elopment of sophisticated self-testing rroceitires in both the transportable remote control 0 and the crane-borne receiver. NIonitoring of the 1, microprocessor is provided in the form of a watch-doe ,:ircu i [ , w hich detects the loss of the microprocessor pulses. The loss of the clock pulses should result [ n the watch-doe circuit switching off the receiver outputs to the crane electrical control circuits. H o wever, it is essential that a reliable emergency stop facility is incorporated in the design of the system to cover failure of the crane-borne microprocessor and/or r-,: eiver output circuits. Should the microprocessor fail during a crane operat i o n, it must be possible to release any receiver output ,:ircuit or trip the main supply contactor to prevent farther uncontrolled operation of the crane. The present range of systems does not incorporate the CEGB-preferred LF design feature of deriving the r eceiver output DC signals directly from the received RF signal. The usual method of providing an emergency stop ontrol in VHF/UHF systems is to transmit an emerc eency stop digital signal to the crane-borne receiver. An emergency stop would rely on the successful rethe emergency signal, which would be dependeipt ent on the faultless operation of the receiver. Since the need for an emergency stop could be due to a faulty receiver, it is not acceptable to have to rely on the correct operation of the receiver to release the output circuits. Unfortunately, other essential requirements adopted hv the CEGB from experience with LF crane conm l systems also have not been satisfactorily provided in the UHF/VHF systems. In addition, the systems Jo not incorporate a limited range facility which is as reliable as the LF system. As a consequence, the CEGB has not (as yet) approved a UHF/VHF system kir use on high category cranes in a power station ironment. re fore, t here
Combrned LF and VHF/UHF crane control systems 'hoe systems are a development of the LF system. The [ F system has been retained for providing a limited range facility and supplementing the emergency stop [
%. t.inirement. The VHF/UHF system is used to provide niore secure digitally-coded control signals. There are still, however, the unacceptable design !Latures which have been described for both LF and Nr . 11F / UHF systems and, due to these limitations, combined systems have not been approved for use in power oations. However, the combined LF and UHF/VHF vproach has a great deal of merit and it is expected
to lead to an approved system in due course for locations which do not suffer from LF pollution. 8.3.2 Anticollision systems The most reliable anticollision device used for power station crane systems is a probe and limit switch arrangement. A 4 m probe is attached to each crane and a strike plate mounted adjacent to the probe attached to the other crane, If the probe strikes the plate, it operates limit switches which disconnect the electrical supply to the long travel motor. This arrangement is suitable for use with two cranes which share the same long travel rails. Where two cranes operate on long travel rails mounted in parallel, with one set of rails directly above the other, a different approach must be adopted. An alternative or supplementary method to the probe arrangement is a radio system which uses either the radar principle of comparing a reflected signal with the transmitted signal or the LF controlled range facility. A typical anticollision radar equipment gives advanced warning of possible collision by detecting the change in frequency between the transmitted signal and its reflected signal. The equipment relies on the Doppler effect which arises when the reflected signal frequency is modified by the relative movement between the transmitting source and the reflecting surface. The faster the closing velocity, the higher will be the difference frequency between source signal and reflected signal. When the source and reflecting surface are stationary, no difference frequency will exist. The equipment can thus detect movement and relative velocity between the crane and another crane or stationary object. The equipment comprises a transmitter/receiver unit enclosed in a housing which also holds a circular, paraboloidal, dish antenna. This unit is mounted on one crane and a suitable 0 reflector is mounted on the other crane. A narrow 5 beam is emitted from the 300 mm diameter dish antenna. The transmitter is based on a 'Gunn' diode and the receiver on a 'Schottsky' diode. A self-check system is normally provided to detect failure of either transmitter or receiver. The equipment can be provided for systems operating over a number of distance ranges between the transmitter and reflector, e.g., up to 10 m, 50 m or 100 m. For cranes operating on long travel rails mounted above each other, the radar system requires a number of transmitter receivers angled to detect the other crane over different sections of the rails. The system can suffer from the effects of spurious reflections from surfaces other than the reflector mounted on the other crane. This weakness can be overcome to a large extent by the use of a narrow beam and paying particular attention to the method of installation used for the transmitter/receiver and reflector units. A particular problem is the movement or loosening of the mounting arrangement over a period of time by the vibrations set up by the crane when in operation. 679
1111111/1111rm--_
1PP Telecommunications
Chapter 8
8.4 RF modulation systems The information to be carried by the radio frequency carrier wave can be audible speech in the form of voice Frequencies (VF), coded VF signals or VF data signals. The YE baud of frequencies used for radio systems is nominally 30-3000 Hz. This band is subdivided as
MODULATING WAVEFORM
a AMPLITuRE MCDuLATCN
—
Follows:
1
11
-1
30-300
sub-audible band
300-2000 Hz 2000-3000 Hz
audible band above audible band
' li • .'•-• li i i ',I ,• L J 'ji
The three sub-bands are isolated from each other by use of a combination of low pass, band pass and high pass filtering techniques. Speech signals are confined to the audible band and non-speech data or coded signals can use in-band or out-of-band signals. Examples of sub-audible and in-band signalling are given in Section 8.4.3 of this chapter under continuous tone control signalling systems (CTCSS) and selective calling systems (SELCALL) respectively. Examples of in-band and above audio band signalling are also given in Section 8.9 of this chapter, which deals with remote control signalling between operator control units (controllers), the radio frequency channel common equipment arid fixed stations. In these examples, the control signals not required to be transmitted with the RF signals are removed by suitable band stop or low pass filters.
' '1' ' , 11 L
1 '.1-
1 li
,
FREQUENCY MODULATION
ij
mv
UNMODuLATED SIGNAL
id)
c
I
AMPLITUDE CARRIER
8.4.1 Amplitude modulation (AM)
An amplitude modulated wave is formed when the information signal is used to vary the amplitude of the RF carrier wave, while the frequency of the carrier remains constant. Figure 8.13 shows a sine wave (a) which is used to amplitude modulate a carrier wave (b). A carrier wave can be represented by: v, = V, sin w t,
(8.5)
where V, is the amplitude and w/27 is the frequency of the carrier wave. The amplitude modulated carrier wave can be represented by: V im = V, (1 + m sin w s t) sin
co t,
(8.6)
where m varies with the magnitude of the audio signal and w 5 /27r is the frequency of the audio signal (Fig 8.13 (d)). The factor m is referred to as the depth of modulation or modulation factor.
Equation (8.6) can be expanded: v im = V, sin w t +
mv,
2 680
cos(w
w s )t
cl+f s )
FREQUENCY
fic. 8.13 Waveforms for AM and FM systems of modulation
The first term is the unmodulated carrier wave: the second and third terms are called the lower (LSB) and upper sidebands (USB), respectively, see Fig 8.13 (e). The amount of modulation applied to the RF carrier wave is measured by the depth of modulation (m). To avoid distortion, the amplitude of the modulation signal has to be limited to ensure that a depth of modulation of 100% (i.e., m = 1) is not exceeded. The depth of modulation is generally set to between 60 and 65% using a fixed amplitude, 1000 Hz test signal. This allows for an additional 40 07o modulation to occur during peak excursions in the speech signal before over-modulation distortion can occur. 8.4.2 Frequency modulation (FM)
cos( w — w s )t —
2 mV,
( Hs )
(8.7)
A frequency modulated wave is formed when the information signal is used to vary the frequency of the radio frequency carrier wave, while the amplitude of the carrier wave remains constant.
-
Radio systems Figure 8.13 (c) shows a carrier wave which has been frequency modulated by a sine wave. It has already been shown that a carrier wave can be ;,:rrescritti by Equaiion (8.5) v, = V, sin w i t. carrier ,Aave, frequency modulated by a sine wave ■ irit-orinat;on _siLmal, is represented by: ;3 sill .-Lkt)l,
V. sin 27 IL
(8 8)
is the carrier frequency ..z, is the angular velocity of the sine wave information signal 5 t is the frequency deviation corresponding to -
For
the frequency shift of the carrier
Continuous tone controlled signalling system (CTCSS)
This system uses a sub-audible modulating signal which is continuously transmitted with the associated RF carrier wave. The signal is always present with the RF carrier and is a modulating signal additional to the information signal. The CTCSS code frequency (or tone) is the assiuned audio frequency quoted by the Radiocommunications Agency (RA) of the DTI when a radio licence is issued for the radio system. These standard frequencies are listed in Table 8.1, which is taken from the DTI performance specification MPT1306 - CTCSS for use in the
Land Mobile Services, The CTCSS modulation limits quoted in TvIPT1306 are given in Table 8.2. TAli_E
the peak amplitude of the sine wave information
t= n
2
here n represents the odd integers 1,3,5, etc.
71-
sin Lo s t = sin n 2
8.1
CTCSS standard frequencies, Hz
67.0
110.9
146.2
192.5
71.9
414.8
151.4
203.5
77.0
118.8
156.7
210. 7
82.5
123.0
162.2
213.1
88.5
127.3
16 7 .9
225_7
94.8
131.8
173.8
233.6
103.5
136.5
179.9
241.8
107.2
141.3
186.2
250_2
I- I
Hicrefore, when the amplitude of the sine wave infor-
niatIon signal is at maximum, Equation (8.8) becomes: TABLE 8.2
v fn, = V, sin 27r (1, ± af)t (8.9) From this equation, it can be seen that or represents ;he maximum deviation. The amplitude of the modulating information signal producing an FM radio frequency carrier wave has to he limited to ensure that a maximum deviation (0r) of - 5 NIHz for a 25 kHz RF channel spacing, or ±2 MHz or a 12.5 kHz channel spacing, is not exceeded. This i% a requirement of the IvIPT Performance Specification by the Radiocommunications Agency (RA) of he Department of Trade and Industry (DTI) to restrict he bandwidth of each radio frequency channel, thus presenting interference between channels and making economic use or the radio spectrum. 8.4.3 Signalling systems fliere are five main signalling systems used with power station radio systems, these are: • Continuous tone
controlled signalling system
iCTCSS). • Selecti‘,e call signalling (SELCALL). • Fast frequency shift keying (FFSK).
• CCITT dual tone multi-frequency (DTMF) signalling. • CCIR sequential single frequency code (SSFC) signalling.
CTCSS modulation limits
System channel spacing, kHz
Amplitude modulation depth, 'ro
Angle peak deviation Hz
25
10 to 20
400 I D 800
12.5
10 to 20
200 to 400
A radio system which uses CTCSS incorporates a CTCSS codec (coder/decoder) in both the fixed stations and the mobiles. The output of the CTCSS decoder unmutes the output of the receiver audio stages, allowing audio to reach the loudspeaker when the RF carrier contains the correct CTCSS code frequency. The coder audio frequency output modulates the transmitted RF carrier with the assigned CTCSS code frequency. CTCSS systems are used to reduce the irritation experienced by users sharing an RF channel, which is often the case for power stations when the channel is shared with an associated second power station or construction site, or with other members of the fuel and power industries using the common group of radio channels allocated to them by the Joint Radio Committee (JRC). Selective call signalling system (SELCALL)
This signalling system uses in-band and above audio band frequencies. There are three main code systems 681
Telecommunications
Chapter 8
which come under the generic name SELCALL. These are known as: • EEA — recommended by the Electronic Engineering Association — UK preferred.
ADDRESS TONES
ALARM RESET
• CC1R — recommended by the Comite Consultatif International de Radio. • ZVEI — recommended by the Zentralverband de Electrotechnichen Industries, or DZVEI (depressed ZVEI) an alternative to ZVEI with lower signalling frequencies. Table 8.3 contains a schedule of the frequencies associated with each code system.
LINK ESTABLISHMENT TIME
EACH TONE 40 ms (EEA) 70 rns /ZVE1 DZVEI 100ms (CC1R)
NOTE TONES l• VI REPEATED AT APPROX 30 SECOND INTERVALS FOR ALARM
FIG. 8.14 Code format for the 5 and 6 tone SELCALL TABLE 8.3 SELCALL code systems
Digit
EEA and CCIR
ZVEI
DZVEI
* Group
1055
970
825
1
1124
1060
970
2
1197
1160
1060
3
1275
l270
1160
4
1358
1400
1270
5
[446
1530
1400
6
1540
1670
1530
7
1640
1830
1670
8
1747
2000
1830
9
1860
2200
2000
0
1981
2400
2200
Repeat
2110
2600
2400
Alarm/ reset
2400
2800
2600
*for ME5 ZVEI, compatible group tone is 2800
Fast frequency shift keying (FFSK)
Tone frequencies in Hz
This system uses two in-band VF signals to represent the two digital bits 0 and I. FFSK is similar to the frequency shift keying (FSK) system used for the control signalling between controllers, common equipment and fixed stations, as described in Section 8.9 of this chapter for the Philips Telecom M87 control system. FSK used in the M87 is at present limited to 300 Bauds (bits/s) signalling rate. FFSK specified for trunked radio systems in the Radiocommunications Agency of the DTI performance specification MPT 1327, operates at 1200 Bauds. The name frequency shift keying is derived from the fact that the frequency shifts from that used to represent bit 0 to the other used to represent bit 1 in a digital word. Figure 8.15 shows the basic signalling format specified in MPT 1327 for the FFSK signalling system. The Link Establishment Time (LET) section comprises one of the FFSK frequencies transmitted for at
The system preferred for power station radio is 5-tone EEA, which is also UK users preferred. Figure 8.14 shows the code format for 5 and 6 tone sequential codes. A call to mobile number 99 would result in a 5 tone SELCALL address, where address tones I, II, III, IV and V would be ORR9R. The frequencies representing digits 0 to 9 and repeat (R) are given in Table 8.3 under EEA. The sixth element of the address is used for remote alarm reset, which is not normally used in power station systems. The SELCALL system can be used as an alternative to, or in addition to, CTCSS. Each mobile which has an individual SELCALL code can be called from a desk or table-top controller by depressing the relevant buttons on a SELCALL digital keypad followed by depressing a 'send' button. The 5 682
sequential tones are transmitted as a VF modulation on the RF carrier wave. The associated mobile SELCALL decoder will detect the code and unmute the audio stages of the receiver, allowing a calling signal to be heard. The receiver remains unmuteci under control of a timing circuit which is reset each time the mobile transmitter is operated within the time-out period. If no transmission is made during the time-out period, the receiver will revert to a muted condition. A manual unmuting switch is provided to enable the mobile user to listen to the radio channel, thus ensuring that it is not busy before he transmits a call to a controller or to another mobile. Where SELCALL is used for operations mobiles and CTCSS is used for other mobiles associated with maintenance and common services, the operations mobiles will also include CTCSS transmit facilities. SELCALL can also be provided in the mobile to fixed station direction, enabling mobiles to call individual controllers and mobiles.
Radio systems
DTMF
: LEI
PREAMBLE
MESSAGE
FRED Hz
vist 6 bit periods, which for 1200 bits/s is 5 ms. Sigpalling transmissions are preceded by the LET. comprises the first and second FFSK The Preamble frequencies transmitted alternately. Each frequency is transmitted for one bit period, i.e., 0.8 ms. The preamble comprises a minimum of 16 bits and ends with a binary 0 bit. The Message is a contiguous transmission comprisv i [ a codeword synchronisation sequence, an address codeword and, where appropriate, one or more data odewords. c The Hangover Bit (H) terminates signalling transmissions by appending either a binary zero or binary one to the last transmitted message to provide even parity of the total binary ones transmitted. The message can be a control code from a controller to the common equipment and/or fixed station, or the number for calling an individual mobile transceiver. Similarly, from the mobile, the message can be a calling code for a controller or another mobile. In a trunked radio system, the RF channels allocated for use by a power station are divided into one control channel and the remainder traffic channels. The calling message from the mobile will be received by the control channel receiver. The control equipment checks that a traffic channel is available and returns an audible signal to the mobile to confirm that the call can proceed. The mobile user then keys the number of the required mobile or controller. On receipt of the message signal, the common equipment checks that the called mobile is available and, on receipt of confirmation of this, automatically switches the mobiles to the synthesised frequency of the available traffic channel and ends a calling message to the called mobile to initiate a calling audible signal in that mobile. Once the two mobiles are switched to the traffic channel the control equipment will deal with the next call. All signalling between control equipment and mobiles \\ ill use the FFSK signalling format.
CCITT dual tone multi-frequency (DTMF) signalling DT:MF signalling comprises two in-band audio signals transmitted simultaneously from each one of twelve keys of a standard telephone keypad, i.e., figures one to zero and the gate and star keys. The frequencies specified by the Comite Consultatif International de Telegraphique et Telephonique (CCITT) are shown in Fig 8.16. The DTMF code is normally used from the mobile to the fixed station or from mobile to mobile in a similar manner to SEECALL.
1
2
3
770
4
5
6
8
852
7
8
9
C
941
Fat,. 8.15 Basic format for N1PT1327 FFSK signalling system
1209 1336 1477 '633
697
0
A
.1
0
DIGT OR LETTER
2
3
1-
4
5
7
8
*
0
1
6 9
I VOL A
l
1 181
SSFC FREQ. Hz 1124 1197 1275 1 358 DIGIT
2
3
4
1446 1540 1640; 5
6
1747118sol'961 2 , to
7
8
9
R
Fro. 8.16 DT1V1F signalling format and keypad
Usually Comite Consultatif International de Radio (CCIR) sequential single-frequency code (SSFC) is used in the fixed station to mobile direction.
CCIR sequential single frequency code (SSFC) signalling SSFC signalling comprises eleven frequencies ranging from 1124 to 2110 Hz as shown in Fig 8.16. Each frequency represents the digits 'I' to '0' and a repeat digit 'R'. The duration of each frequency/tone is 100 ms in accordance with the CCIR recommendation. The system is used for selective calls between the fixed station and mobiles. This signalling system is used in trunk radio schemes such as the Motorolla-Storno CAF2200 system.
8.5 RF propagation In order to design an adequate radio system for use in a power station it is necessary to determine the propagation of radio signals that can be achieved from the antenna systems located in the station. The equations used to determine the RF propagation from an antenna are based on the theoretical point source antenna called an isotropic radiator. The power density P (W/m 2 ) at a point R metres away from an isotropic radiator due to power P 1 transmitted by the radiator is given by: P = P 1 /47R 2 W/m 2
(8.10)
The equivalent electric field strength E in volts/metre (V/m) for a power density P is determined from: P = E 2 /1207r W/m 2
(8.11)
where 1207r (377) is known as the resistance of free space (see Fig 8.12). From Equations (8.10) and (8.11) we get: E
(30
P1) 2
V/m
(8.12) 683
Telecommunications
Chapter 8
For an antenna having a gain G, with respect to an isotropic radiator, Equation (8.10) becomes: P = P,G,/47rR 2
(8.13)
and Equation (8.12) becomes E
OOP ,G,) • R V/m
(8.14)
For a half-wave dipole in the direction of maximum radiation P = 1.64 P 1 /(47i-R) 2 W/m 2
(8.15)
E = (49.2 P,) 2 /R V/m
(8.16)
Note that the gain G, of a half-wave dipole is 1.64 (2.15 dBi) with respect to an isotropic radiator in the direction of maximum radiation, i.e., normal to the axis of the dipole. 8.5.1 RF received power To determine the power intercepted by a receiving antenna, it is necessary to determine the effective area of the antenna when intercepting a given radiated power density. Let the radiated power density be P W/m 2 , then the effective area of an antenna is given by: Area = (G 1 X 2 m 2 )/47r
(8.17)
where G r is the gain of the receiving area with respect to an isotropic radiator and X is the wavelength of the RF propagated wave. The power P r (watts) intercepted by an antenna having an effective area of A is P x A in the direction of maximum radiation. Using Equations (8.13) and (8.17), this becomes: P r = P,G,G,X 2 /(41- R) 2 W
(8.19)
To find the loss of the free space between two isotropic radiator antennas, i.e., allowing the gain of each antenna to be unity, then Equation (8.19) becomes: 2 Pr/Pi = (X/47rR)
(8.20)
Loss = 10 log P r /P, = 20 log X/47rR
• BICC radiating cable T3537 with apertured tape has a coupling loss of 74 dB for a 450 MHz UHF signal and a distance of 3 m to the receiving dipole. From Equation (8.19), the loss between an internally mounted dipole transmitting antenna and a receiving dipole can be calculated from: Loss = 10 log P r /P, = 20 log (1.64) 2 (0.67) 2 /47rR which gives a loss of 30 dB at 3 m and 36 dB at 6m. From the results, it can be seen that an internal antenna would have a theoretical gain of 39 dB over the Andrews radiating cable (leaky feeder) and a 44 dB gain over the MCC radiating cable (leaky feeder). For this reason, antenna systems used in power stations comprise a combination of internal antennas and radiating cable. The antennas are used in the larger open areas such as turbine halls, boiler houses, etc., and radiating cable for confined areas such as cable tunnels, corridors surrounded by thick reinforced concrete walls, floors and ceilings.
(8.21)
Using Equation (8.21), the graph in Fig 8.17 of loss for free space propagation between two isotropic radiators can be obtained. The graph shows the effect of the inverse square law on the attenuation through free space, i.e., an 684
• Andrew Antennas radiax slotted cable RX4-2R has a coupling loss of 75 dB for a 450 NilElz UHF signal and a distance of 6 m to the receiving dipole.
(8.18)
To determine the loss of free space, Equation (8.18) has to be rearranged to obtain: 2 2 Pr/Pt = GEG r X /(47rR)
increase of 6 dB each time the distance from the antenna is doubled. When considering on-site UHF systems and off-site VHF systems, the effect of free space loss is more pronounced in the UHF systems because the increase in attenuation is greater at short distances from the antenna, e.g., at 30 m from the antenna the free space loss is 55 dB and, at 300 m, it is 75 dB. As the distance from the antenna increases, so a 6 dB change in free space attenuation represents a much larger change in distance from the antenna, e.g., at 15 km from the antenna the free space loss is 109 dB and, at 30 km, it is 115 dB. Equation (8.19) can also provide interesting data when an internal dipole antenna is compared to a radiating coaxial cable (leaky feeder) for use inside power station buildings. Section 8.6.3 of this chapter gives details of radiating coaxial cable systems. Two radiating cables (leaky feeders) used for power station radio systems have the following coupling losses between the radiating cable and a dipole located 6 m and 3 m away respectively:
8.6 Antenna systems 8.6.1 Antennas
Antenna systems used in power stations have to be designed within the following Joint Radio Committee
Radio
systems
LOSS FOR FREE SPACE PROPAGATION
450 MHz 5,
Lel G t O n P t
'a X
2
/
1
1
2
-d8 = 101"4Rt2
20
3m FREE SPACE LOSS TO ISOTROPIC = 35c16 TO DIPOLE = 3308 COUPUNG LOSS BICC CABLE
10
5
15
20
FIG.
= 42dB = 4008
COUPLING LOSS ANDREWS
- 8008
40 30 25 35 DISTANCE FROM TRANSMITTER ANTENNA. m
45
50
55
00
8.17 Graph of loss for free space propagation
RC) li mits on RF transmitted power from an anten-
na. External antennas must be limited to a maximum effective radiated power (ERP) of 2 W and indoor antennas to 5 W (ERP). ERP is defined as the average power supplied to the antenna by the transmitter during one RF cycle under conditions of no modulation multiplied by the gain, relative to a half-wave dipole, of the antenna system in the direction of maximum radiation. The antenna(s) used for a particular antenna system are selected on the basis of the following: • Operating frequency. • Polarity of the radiated field. • Direction of radiation. • Bandwidth. • Power handling capability. • Input impedance. • Mounting arrangement. • Wind loading. 'lie operating frequency will depend on the radio
'Ys tem, i.e., a
7406
Sm FREE SPACE TO ISOTROPIC TO DIPOLE
VHF lowband, midband or high band
'.stem, or a UHF system. The polarity used for power station radio systems
Is usually vertical polarity, i.e., the radiating element is mounted perpendicular. to the ground. This also
means the electric field, the E-plane of the radiated signal, is also perpendicular to the ground and the magnetic field, the H-plane, is parallel to the ground. The direction of radiation for maximum transmission or reception will be either omnidirectional or unidirectional. The direction of the radiation from an antenna is shown on H-plane and E-plane polar diagrams. The two polar diagrams are required because the radiation is three dimensional. Usually for omnidirectional antennas, where the H-plane polar diagram is represented by a concentric circle with the antenna at the centre, only the E-plane polar diagram is given in the manufacturer's technical data sheets. Figure 8.18 shows a Philips Telecom Type CAT omnidirectional colinear antenna. Figures 8.19 and 8.20 are E-plane diagrams for the VHF low band and UHF versions, respectively, of this antenna. The polar diagrams are drawn on a graph of concentric circles. The convention used is to call the largest circle reached by the largest lobe of the polar diagram the 'reference circle'. Circles are then drawn through 3 dB points from this reference circle, i.e., circles representing 0, —3 dB, 6 dB, etc., are drawn, with the outer reference circle representing 0 dB. Figure 8.19 is the E-plane diagram for a Type CAT 80 antenna, which is the VHF low band version having a maximum gain of 3 dB with reference to a halfwave dipole. The graph circles therefore represent gains of 3 dB, 0 dB, —3 dB and —6 dB, starting at 685
Telecommunications
Chapter AM.
135 120 105 90 75 .\. ,," \ ,z'' \----'
150
165
1
•
,
60
45
1. • (
180 352 195\ 210'
225 -
240 255 - 270' 285 300
315'
330
E - plane polar diagram for a Philips VHF
FIG. 8.19
CAT 80 antenna
135'
:i TIPble ' , WALV ‘r" 111111111 ra e
11 68
15.
1 Pl.*11
210'
225
FIG. 8.20
FIG. 8.18
45' 30'
195'
GAIN 3db(VHF), 5db (UHF) SLIM, TAPERED DESIGN RUGGED, GLASS-FIBRE PROTECTION: FOAM ENCAPSULATION EASY MOUNTING
120° 105' 90' 75' 60'
150
V
0, 360
-11A
ratit
240 - 255' 270' 285' 300'
315'
330
E-plane polar diagram for a Philips UHF CAT 460 antenna
—2 dB with respect to a half-wave dipole in directions of 70 ° and 110 ° from the horizontal. The required bandwidth of the antenna will depend on the number of fixed station frequency channels which are to be transmitted or received and whether the antenna is to be used for transmit and receive functions. The bandwidth is conventionally taken as the frequency band between the 1.5 VSWR points on the VSWR/frequency graph for the antenna, where VSWR stands for the 'voltage standing wave ratio':
Philips Telecom VHF/UHF colinear antennas type CAT
VSWR -= the laigest reference circle and moving towards the centre. Figure 8.20 is the 1-plane diagram for a Type CAT 460 antenna, which is the UHF version having a maximum gain of 5 dB with reference to a half-wave dipole. The graph circles therefore represent gains of 5 dB, 2 dB, —1 dB and 4 dB, starting at the largest reference circle. The polar diagram shows a number of secondary lobes, the largest of which have gains of approximately 686
Emin
where Em
= voltage at crest of standing wave
E r„,,, = voltage at trough of standing wave The VSWR is a measure of the impedance match between the characteristic impedance of the antenna coaxial cable and the impedance of the antenna. The characteristic impedance of a cable is the input impedance of an infinitely long length of the cable. In
Radio systems practice, this is the value of impedance which, when terminating any length of the cable, will produce an ut impedance of the game value. n For a perfect match between the coaxial cable and the antenna impedances, there is no reflected signal from the antenna/coaxial cable connection and thereand the fore no standing wave, i.e., I E mu ,' = I R = 1. For a \,alue of antenna impedance which is less or [tie:1[er than the characteristic impedance of the coaxial ble he vsWR will be greater than 1. I Emax 1
VSWR —
I
Emm
I F11+1Erl
I
I
Er
I
—
E
(8.22)
I
voltage of the forward travelling wave
0. here Er
= voltage of the reflected wave
Er
— 0, VSWR = 1
when E r
1.5, I E max 1 = 1.21 Ef I and I E m m = 0.8 I Ef I
For VSWR
To appreciate the meaning of VSWR 1.5, it is useful to calculate the impedance of the load of the antenna ..ompared with a coaxial cable characteristic of 50 0. Co do this, the following equations can be used: Z — Zo
Q
(8.23)
Z + Zo
= voltage reflection coefficient
where
From which P = 4SP/(S
1) 2
For VSWR = S = 1.5, P = 0.96 P m , i.e., for a VSWR = 1.5, 96 07o of the power that would be delivered to a matched load is delivered to the unmatched antenna; this is equivalent to a loss of 10 log 0.96 = 0.2 dB. From Fig 8.21, it can be seen that the bandwidth between the 1.5 VSWR points for a VHF version of the CAT 80 antenna is approximately 2.5 MHz. From Fig 8.22, the bandwidth of a CAT 460 UHF antenna is approximately 22 MHz. The VSWR/frequency graphs for the CAT 80 and the CAT 460 antennas show that, at the design frequency for the antennas, the VSWR is approximately 1.15 and that the VSWR changes with frequency. The power handling capability of the antenna will depend on the maximum RF output of the transmitter. For a CAT type antenna, the maximum input power is 150 W, which is well above any transmitter output used for a power station radio system. The input impedance of an antenna is specified for the design frequency and will vary between the VSWR 1.5 points of the antenna bandwidth. For power station systems, the design impedance is usually 50 0: this varies between 50 and 75 0 over the design bandwidth of the antenna. The mounting arrangement will depend on the type of antenna chosen. The mounting arrangements for a CAT type colincar antenna suitable for masthead mounting are shown in Fig 8.23.
Z = antenna impedance, 0 Zo = characteristic impedance of the coaxial cable, 0 The modulus of the voltage reflection coefficient o determined from the VSWR:
I z - zo I Iz+ zoi
Is -I I Is+
e
3.0 —
I
. 0000000.
44,
20— 10—
(8.24) 2.0 —
here S = VSWR = 1.5 and if Zo = 50 0 then
I z
-
501
0.5
1 Z +501
2.5
giving 1 Z1 = 75
The power delivered to the antenna at a VSWR = 1.5
> 1 5—
Lan be calculated using: Mismatch loss = P rn /P " h ere Pm + power delivered to a matched load P = power delivered to the antenna P in
(s - Q1
2
1 0
78
79
80
81
82 FREQUENCY MHz
83
[ 84
85
+ 1) 2
4S
Fm. 8.21 Gain and VSWR curves for a Philips VHF CAT 80 antenna 687
Telecommunications
cc
Chapter 8
1 5
•J")
TYPE NO
FREQUENCY SAND MHz FOR 1 5. 1 MAX VSWR)
CAT 390 CAT 400 CAT 420 CAT 440 CAT 460
380 - 396 396 - 412 412.430 430 - 450 450 •470
Fib. 8.22 VSWR curves for Philips UHF CAT
antennas
Folded dipole antennas which can be used for both VHF and VHF systems are supplied with a mounting boom. Figure 8.24 shows a typical folded dipole antenna, the Philips Telecom Type ANSDH, which has a 38 mm diameter mounting boom. Figure 8.25 shows the typical mounting crossover clamps used to attach the boom to a mast. The mast fixing arrangement must be capable of withstanding a wind loading of 160 km/h. For power station external antennas the mast is usually clamped to a suitable wall or to metal girder sections at two points along its length. The Type ANSDH 460, or similar, is used as an internal antenna for UHF on-site systems. When used in this way, the mounting boom can be supplied with a wall bracket and enough boom length to allow the wall to antenna spacing to be adjusted between 3/16 and 1/4 of a wavelength. The spacing should be adjusted for maximum radiation. Figure 8.26 shows the effect of the proximity of a mast on the polar diagram of the antenna. In this case, a boom length of 1 wavelength or more will give the best omnidirectional pattern. When designing/installing antenna systems, it is necessary to reduce the coupling between transmitter and receiver antennas used for a common two-frequency simplex channel and between antennas of different channels. This is necessary to prevent unwanted signal levels appearing at the output of transmitters and the input of receivers, which could result in intermodulation interference. Figure 8.27 shows the relationship between isolation in decibels and the vertical separation between the antennas, while Fig 8.28 shows the relationship between isolation in decibels and horizontal separation between the antennas. Comparison of the two figures shows that the vertical separation is more effective than the horizontal, e.g., at 450 MHz, 35 dB isolation can be obtained by vertical separation of 0.6 m or by a horizontal separation of 4.2 m. 688
Irs line Olt set Masillead Camp
Parallel Clamp
Parallel Clamps
AG.
8.23 Clamping arrangements for CAT
antennas
Radio systems
FIG. 8,25 Typical crossover/parallel clamps for boom-
mounted folded dipoles
i(,. 8.24 Folded dipole antenna, Philips type ANSDH
8.6.2
Typical antenna arrangements
In the past a typical external antenna arrangement for rower stations comprised a mast with folded dipoles for He transmitter and a common omnidirectional high Lia m antenna for the receivers. The high gain receive Antenna was mounted at the top of the mast and the bolded dipoles 3 m below. Flgures 8.24 and 8.29 show a typical folded dipole and the dipole characteristics: Figs 8.30 and 8.31 illustrate a typical high gain omnidirectional antenna (Philips Type ANSA) and its associated characteristics. The high gain antenna consists of four vertical dipoles iflaunted on a 38 mm support tube. The dipoles are
fed in a suitable phase relationship by a matching harness which is attached to the support tube. Gain in the direction of maximum radiation is approximately 5 dB relative to a half-wave dipole. Figure 8.31 shows the H-plane radiation patterns which can be obtained by re-arranging the dipoles, e.g., all four dipoles can be mounted on the same side of the support tube to provide extra gain in one direction, resulting in a gain of 8.5 dB. Figure 8.32 shows the E-plane polar diagram for the high gain antenna. The lobes showing that the direction of maximum gain radiate horizontally. This would result in poor on-site cover from an antenna mounted on a high building. For a high gain antenna mounted on the roof of a turbine hall or boiler house, some E-plane tilt is required to obtain on-site cover. E-plane 689
Telecommunications
SUPPORTING STRUCTURE DIAMETER IN WAVELENGTHS
Chapter 8
at
ow* Mkt
4
2
2k 4
NOTE: 2ND CONCENTRIC CIRCLE REPRESENTS
ANTNNA SPACING TO NEAREST SUPPORT STRUCTURE
RADIATOR PATTERN OF ANTENNA IN FREE SPACE
FIG. 8.26 Effect of spacing on the radiation pattern
1
0
10
20 -
20— Jo
-
ISOLATION. dB
30 —
40
50
60
70
FIG. 8.27
Isolation by vertical separation of antennas
10
SEPARATION BETWEEN ANTENNAS. m
tilts of 5° and 10 ° can be obtained electrically by fitting special matching harnesses which comprise tuned coaxial cable elements. 690
FIG. 8.28
Isolation by horizontal separation of antennas
100
Radio systems
jEREOLJECY! 1 'HAND l! FCR 5' W E JGH T ! LENGTH ■ LESS E3OCM mm
--
—
25
2-23 "
2^.60 123.0 ' €5
2 25 24
'42;
445 1 5
2
MiNIMUM , DISTANCE SPACING • BETWEEN ' FROM ! CENTFIESOF 50M en. I 1 20 MP" 1 STACKED ANTENNA ONLY I MAST , DIPOLES kg mm WiND LOADING AT 193 km ir
58
364
22
2 ' 53
553
)
Si
3
2-
7
I
2 5 _
'27
24 -1 5
I
460
480
BOOM D 45 Kg PER
5 cc
10
55 60 65 70 75 80 85 90 MHz
FIG. 8.29
380
400
420
440
MHz
Folded dipole characteristics
T o ts have shown that the circular E-plane polar trarn of a half-wave dipole can give superior on-site er to a high gain antenna. Alternatively, an antenna .: , t.nvement consisting of two folded dipoles mounted above the other in a cruciform arrangement with i c i• planes parallel and horizontal, will produce a field 1 1 , i ■ ine a circular polarity (i.e., both vertical and horitial) directed downward. This paging system type ini ,Littenna gives localised site cover more suitable for ; , ,mer stations. An antenna of this type is shown in 8.33 which also illustrates the depressed E-plane po[ar diagram sometimes referred to as an 'umbrella' characteristic. This is far more suitable for on-site t. I IF radio systems where the antenna is mounted at ii Th level on one of the power station buildings. In designing the antenna system for a power sta'ion, it is necessary to consider the cover required, the on which the antennas are to be mounted and ai ti-plane polar diagrams of the proposed antennas. it umber of folded dipole antennas located at different around the site and mounted at low level zi‘e better on-site cover than one high gain antenna. [ lie adoption of multiple fixed station operation, to handportable RF outputs to be reduced, also takes the use of multiple antennas mounted at lower k‘els more acceptable. The arrangement that is eventually adopted will be .rerrnined by the size and complexity of the layout yl, power st.ation buildings, the RF output from the :: indportables that can be permitted without causing :na , :ceptable levels of RFI to control and instrumen!mion equipment and the cost advantages which will from use of a radio communications system. 8.6.3 Radiating cable (leaky feeder) Radiating cable is specially designed coaxial cable which a loosely braided or slotted solid copper outer con-
ductor. The hole in the braid or solid copper outer conductor creates three mutually perpendicular elements of RF field; one element parallel with the cable, one tangential with the cable and the other perpendicular to the cable. For RF transmitted from the cable, the latter element is perpendicular in the direction leaving the cable. For RF received from a handportable transmitter, a similar field arrangement is created by the holes but in this case the perpendicular element is directed into the cable. The effectiveness of the radiating cable is measured as a coupling loss. The coupling loss is measured by mounting a dipole 3 m or 6 m away from the cable such that the dipole elements are parallel with the radiating cable. The dipole is connected to a matched, calibrated, measuring RF receiver. One end of the radiating cable is connected to a calibrated RF transmitter and the other end to a matched resistive load. The transmitter is set to a suitable RF input power to the radiating cable which produces a readable signal on the calibrated receiver connected to the dipole. The overall loss comprises the attenuation due to the radiating cable (cable loss CD) between the input connections and the cable opposite the receiving dipole, and the coupling loss (CL) between the radiating cable and the dipole. Table 8.4 shows typical cable attenuation and coupling losses for a BICC radiating cable Type T3537 and an Andrew Antenna radiating cable Type Radiax R4- 2R. Figure 8.34 shows a fixed station transceiver connected to a length of radiating cable through a coupling interface (CI). The maximum attenuation (MAF) between a fixed station transmitter and a handportable receiver is determined by subtracting the minimum operational power required at the input to the receiver from the output power of the fixed station transmitter. These powers 691
Telecommunications
Chapter 8
135'
120'
105
90=
7
60' 30
150
165
180
0•
195 -
345•
210-
330 225'
240' 255' 270' 285 - 300: OFF-SET PATTERN
135'
120"
105' 90
75 -
315
60' 30
150'
165' 180'-
360 .
195'
345'
210'
330' 225'
240° 255- 270' 285' 300' ELLIPTICAL PATTERN
315'
Flo. 8.31 H-plane polar diagrams for high gain antenna Philips type ANSA
135'
120' 105' 90' 75' 60'
45'
150'
165'
180'
30'
rata4W#*Aim ts.
195'
225' 240' 255 270' 285' 300" FIG. 8.30
Philips type ANSA
Or 360' 345:
I
210°
15'
330' 315'
high gain antenna FIG. 8.32 E plane polar -
diagram for high gain antenna Philips type ANSA
are usually quoted in decibels with respect to 1 W (dBW), i.e., dBW = 10 log
Measured power One watt
measured power, in watts)
692
(or 10 log
The maximum attenuation (MAH) between a handportable transmitter and a fixed station receiver is found in a similar manner.
Radio systems In order to calculate MAF and MAH it is necessary to determine the losses involved at the handportable. In both receive directions, although the minimum receiver sensitivity is of the order of 0.5 V pd (1 12 V Els/IF, see Fig 8.36), a minimum operational sensitivity of between 2 and 5 AV EMF would normally be used to design the system. The body proximity loss ( BP) for the handportable is not necessarily the same for transmit and receive. This is because during transmit the handportable is held at head level and during the receipt of a call it could be attached to a belt or in a pocket. This could result in a BP of up to 3 dB for transmit and up to 6 dB for receive. For a receiver with an operational sensitivity of 2.5 Pd ( 129 dBW), a fixed station transmit power of 25 W (14 dBW) and a handportable transmit power of 0.5 W ( — 3 dBW) into the antenna, N1AF and MAH can be calculated as follows: —
MAF = 14 — (-129) = 143 dB MAH = —3 — (-129) — 126 dB Using these values for MAF and NIAH the cable distribution loss can be calculated from the following equations, see also Fig 8.34. MAF = CI + CD + CL + RD + BPL + AL (8.25)
MAH = AL + BPL + CL + RD + CI
(8.26)
where AL = antenna loss BPL = body proximity loss CD = cable distribution loss CI
cable interface loss RD = Rayleigh distribution loss
FIG. 8.33
Paging type antenna — Jaybeam type 7395 693
Chapter 8
Telecommunications TABLE 8.4 Typical cable attenuation and coupling losses Attenuation dB/I00 m
Radiating cable
Nominal diameter
Frequency
BICC 13537 50 ,:? ..- able ( Aperr Lirecl ape)
13 mm
85 X1Hz
2.8
450 MHz
6.8
Coupling loss 64 dB at 3 m 67 dB at 6 m 7 -1 dB at 3 m 77 dB at 6 m
Andrews 1(4- 2R
13 mm
55 MHz
3.6
69 dB at 6 m
450 X1Flz
1 0.5
7
(Slotted screen) 5 dB at 6 m
FIXED STATION
RADIATING CABLE RADIO TRANSMITTER
CI
CdBW
CD
5011 TERmiNATLNG RESISTOR
RADIO RECEIVER
CL . RD
AL BPL CD CI CL RD
ANTENNA LOSS -
BODY PROXIMITY LOSS
= CABLE DISTRIBUTION LOSS = CABLE INTERFACE LOSS
1-( ANDPORTABLE
- COUPLING LOSS RAYLEIGH DiSTRuBITON LOSS
FIG. 8.34 Calculation of maximum cable distribution loss
Since N4AH is smaller than MAF the former would normally be taken as the value to carry out the calculation of CD. However, in practice, since the cable interface loss (CI) and 13P loss differ for the transmit and receive directions it is prudent to calculate CD for both
directions.
wave created in space with the signal strength following a Rayleigh probability distribution. A typical standing wave is shown in Fig 8.35. It can be seen that the signal strength varies between the minimum of 10 dB to the maximum of 20 dB, i.e., a total variation loss of 10 dB.
The cable interface loss (CI) could be 3 dB in the transmit direction for a single-transmitter/receiver arrangement or up to 6 dB for a 5-transmitter arrangement. In the receive direction, because an amplifier could be used before the receiver, the Cl would be dependent on the gain of the amplifier used. A typical value for CI would be — 10 dB (i.e., a gain of 10 dB). The Rayleigh Distribution loss (RD) covers the losses
experienced by a handportable while on the move. The loss is due to multiple path reflections causing variation in the received signal due to the complex summing of signals received from the radiating cable direct, and signals reflected from the walls, ceiling, floors and plant. As the receiver moves through the field, the signal strength plotted against distance will reveal a standing 694
LINEAR DISTANCE. X 2
Ftc. 8.35 Signal intensity plotted against distance in a multipath environment (Rayleigh Distribution)
Radio systems Referring to Fig 8.36 (a), it can be seen that in order receiver input of 2.5 V pd the EMF ext o obtain a ted by the antenna from the radiating field must , rac N, i.e., 126 dBW. I In the transmit ditection, Fig 8.36 (b) shows that output of 1 W is necessary in order to .t cransini[f,:r ,ftilOcr 0.5 N,1 into the antenna. radiating cable coupling loss is specified as , Sin :e [he bet‘een he cable and a two-element hall-wave Ji ro le, the handportable antenna loss (AL) must be \\,ith respect to a dipole. The antenna is either wavelength monopole or helical antenna. ,t quarter 8.37 shows the relationship between a monoFiI' Ve pole lia%..ing a practical ground plane and a dipole. The parallel to the ground plane is shown to be —3 dB
ORTHOGONAL CONDUCTING PLANE
(a)
CONDUCTING PLANE
ith respect to a dipole. For a handportable the ground plane is likely to be ,ornplex and difficult to determine. The value of body pro \ imity loss ( BP) includes any loss due to a poor round plane. Tables 8.5 and 8.6 identify typical handportable menna losses obtained in practice. ,i Typical values for each of the losses required in oricr to determine the maximum cable distribution are as follows:
Ei2 Ez2
(b)
= 3 dB 11 BPL = 3 dB for transmitter and 6 dB for receiver = to be calculated CD - 3 dB for a single transmitter and up to Cl 6 dB for 5 transmitters
: a.Ea NP T POWER
2 - 2x -V
x 1 so
50
90•
10ADIAMETER GROUND-PLANE iNFINITE GROUND-PLANE
W
W
Vpd
pV 2 RECEIVER NPLIT IMPEDANCE
(c)
FIG. 8.37
Effects of ground plane on a monopole antenna
(a) Dipole element into which a thin conducting sheet has been inserted. (b) Showing how a voltage generator can be split so that connection can be made to the conducting plate to form two
0 5W DELIVERED TO THE ANTENNA
8.36
Calculation of receiver input powers
identical and separate monopoles, each having a feed point i mpedance half that of a dipole. (c) Free space radiation patterns of X/4 monopoles over perfectly conducting ground planes of various diameters. The infinite ground plane shows a 3 dB gain over a dipole a 0 0 elevation angle, but any finite ground plane will exhibit a 3dB loss.
CI = — 10 dB (gain) for receiver CL = 80 dB MAF = 143 d13 MAH = 126 dll 595
Telecommunications
Chapter 8
From Equation (8.25)
0.105 = 295 m. Thus the total amount of radiating cable that can be used is increased to 10 + 2 x 295 = 600 m. This procedure can be repeated to produce a complex radiating cable and internal antenna system (see Fig 8.39).
CD = MAF - CI CL - RD - BPL - AL = 143 - 6 - 80 - 10 - 6 - 3 = 38 dB From Equation (8.26) CD =MAFI- AL BPL - CL - RD - Cl = 126- 3 - 3 - SO - 10 - (-10) = 40 dB For Andrews (R4-2R) type radiating cable and an operating frequency of 450 MHz, 38 dB is equivalent to a length of 362 in of cable which is not sufficient for use in a complex antenna system required for a power station. However, if the transmitter is connected to the centre of the radiating cable, as shown in Fig 8.38, the radiating cable either side of the power splitter can have a maximum loss of: 38 - (3.5 + 3.5) = 31.0 dB Since at 450 MHz Andrews (R4-2R) radiating cable has an attenuation of 10.5 dB/100 m, the length of cable on either side of the power splitter can be 31.0/
8.7 RF fixed stations The RF fixed stations are distributed throughout the power station to ensure good radio cover. Each fixed station consists of a transmitter, receiver and an antenna system coupling equipment. The complexity of the coupling equipment will depend on the number of transmitters and receivers which have to be coupled to the antenna system and the number of RF channels that have been allocated for use by the radio system. Each RF channel will require a fixed station transmitter/receiver. The coupling equipment could comprise: duplexers for coupling a receiver and transmitter to a common antenna system; diplexers for coupling two transmitters to a common antenna system; a receive amplifier for connecting a number of receivers to a common receive port of the coupling equipment; circulators and kolators for connecting transmitters to a common antenna system, thus reducing the effects of reflected or unwanted signals returning to the transmitter. A corn-
TERMINATING RESISTOR
son
75dEt AT 6m 24.4dB = 232m
rTi
ANTENNA GAIN -MB RECEIVED SIGNAL TO BE 5p,V MINIMUM = -26c18W
HAND PORTABLE
ANDREWS RADIATING CABLE R4-2R '0 5 (113•'00m AT 450 MHz OcIeW
UHF TRANSMJTER
10m
3.1de (POWER SPLITTER)
3 5dB
3 . 1 dB
REC,EIVER 24.4a = 232m
TOTAL LENGTH OF RADIATING CABLE = 474 m
50n TERMINATING RESISTOR
FIG. 8.38 Centre-fed radiating cable arrangement
696
4
ii(,11 GAIN Al nix. ON 151m
» 11 vEL
DI 3168
:1 0r rl Odad
42m LEVEL OL - 12 5dB
IA
30m
12 5m LEVEL
REACTOR 7 HIGH GAIN DL 29013 V IA
15m
(I SOB)
= 18dB V HIGH GAIN EA ON 14m ROOF LEVEL OF (ED BUILDING
NR 20m (1013)
3orn FI (1 SilkS
TERMINATING
(3d B)
8dB
NR
T
EA DL 12 5208 ON 37m ROOF LEVEL (SE CORNER)
CORM_ R)
E A
DL 25 5dB
RESISTOR 25m (2 50B)
T
IA
30m (1 5dB)
DL - 22 5dB HIGH GAIN
12 5m LEVEL REACTOR 8
NH
20 111 (1dB)
40m NR (2dB)
IIRRADiATED FUEL DISPOSAL (IFD)CONTROL ROOM 125m LEVEL
—
6d81
1m
5m(1 508)
20m (2dB)
STAIRWAY
40m (4dB)
S rAlFiWAY
24m (2 506) 1dB
T
1508 15m
I
BOB
NA
V IA REACTOR 7 BASEMENT DL = 31.5dB
20m (1dB)
TX
I AX I
SYSTEM 1
-9m LEVEL
1 dB
AMP
I
TX
RX
SYSTEM 2
I
I,
TX
I
AX
SYSTEM 3 IA
DL 23 5dB
DL = 24dB \
FUEL
POND (1 5dB) 15m
POWER SPLITTER
DIPLEXER
DUPLEXER
REACTOR 8
BASEMENT 6dB
I NR I 5m (1dB(
-Ill) LEVEL
IA INTERNAL AERIALS EA EXTERNAL AERIALS TX TRANSMITTER AX RECEIVER AMP RECEIVER AMPLIFIER DISTRIBUTION LOSS DL NR NON-RADIATING COAX
8.39 Typical fixed staiion antenna system
swalsAs opeu
FUEL VIA POND DL = 3206
24m (2 5dB)
OdB
/\
Telecommunications bination of all or some of these items of equipment could be assembled to make up an antenna coupling system alitable for a particular location. 8.7.1 Fixed station transmitters The fixed station transmitters used for power station radio system , are ,:aliclarci PMR transmitters designed [o operate at he particular band or frequencies allocated to PNIR use. The fixed stations for VHF low band systems use single-frequency simplex, amplitude modulation (AM) base stations. For the UHF band systems, the fixed stations use two-frequency simplex, frequency modulation (FM):
• Single-frequency simplex operation means that both the fixed station and mobiles use the same RF frequency for both transmit and receive functions. Since the same frequency is used, the fixed station and mobile are unable to operate at the same time (duplex operation). It is necessary, therefore, for the fixed station and mobile to transmit in turn, i.e., single frequency simplex operation. operation means that the fixed station and mobile use different RF frequencies for the transmit functions. The fixed station uses one frequency for transmit which is received by the mobile receiver and the mobile uses a second frequency for transmit which is received by the fixed station receiver. Although two frequencies would allow duplex operation, simplex operation is used for speech because a user of the radio system cannot speak and listen at the same instant. Two-frequency si mplex operation also provides improved mobile to mobile communications by the use of a fixed station talkthrough facility. During talkthrough, any signal received at the fixed station receiver, e.g., from a mobile, is re-transmitted by the fixed station transmitter to other mobiles switched to the same RF channel.
Chapter 8 signalling, is transmitted from the remote controller over a cable connection to the line interface and audio frequency (AF) amplifier section of the transmitter. A crystal-controlled RF oscillator generates the RF carrier wave which is connected via a frequency multiplier to the amplitude modulation (AN1) modulator or frequency modulation (FM) modulator in series with the output of the AF amplifier section. In an AM transmitter, the amplitude of the RF carrier wave is varied in sympathy with the complex AF output from the AF amplifier section and the radio frequency remains constant. In an FM transmitter, the frequency of the RF carrier wave is varied in sympathy with the AF output from the AF amplifer section and the amplitude of the RF carrier wave remains constant. The modulator in an AM transmitter is a non-linear device which has the RI carrier and signal voltages applied to it in series. The modulator in an FM transmitter varies the frequency of the carrier wave to produce a FM signal which, as shown in Section 8.4.2 of this chapter, can be represented by:
• Two-frequency simplex
The transmitter equipment has to comply with the following performance specifications issued by the Radiocotnmunications Agency (RA) of the Department of Trade and Industry (DTI): • For frequency modulated (FM), UHF and VHF equipment — MPT 1326 — Performance Specification for Angle modulated VHF and UHF radio equipment for use at fixed and mobile stations in the Private Mobile Radio Service. • For amplitude modulated AM, VHF equipment — MPT 1302 — Performance Specification for Amplitude modulated VHF radio equipment for use at fixed and mobile stations in the Private Mobile Radio Service. Figure 8.40 shows a block diagram of a typical RF fixed station transmitter. The speech, plus any tone 098
V fm
= Ve sin 27r (f c + 5)1
where F e is the carrier frequency and Sr is the frequency deviation corresponding to the frequency shift of the carrier for the peak amplitude of the information signal Thus for a carrier of 10.7 MHz and frequency deviation of 5 kHz (0.005 MHz), the instantaneous carrier frequency would be 10.705 MHz at the positive peak of the signal and 10.695 MHz at the negative peak. The output of the modulator is connected to a power amplifier driver section which provides the driving signal to operate the power output stage of the transmitter. Since this stage is operating at relatively high RF powers, e.g., 0.5 W for handportables and 25 W for fixed stations, use of a linear Class A amplifier stage would result in significant power losses in the internal impedance of the stage. Figure 8.41 (a) shows a typical transfer characteristic for a Class A amplifier stage. A constant bias centres the signal on the linear portion of the characteristic between the cut-off point for current through the stage and the upper point where current would be drawn by the control circuit. This causes a constant current to flow through the stage which is varied as shown when a RF signal is present at the input. This results in a stage efficiency of between 40 and 65%. For fixed station transmitters the heat generated in the stage would have to be dissipated adequately. For a handportable, this would result in an unacceptable drain on the battery as well as requiring adequate stage cooling. Figure 8.41 (b) shows a typical transfer characteristic of two Class B amplifier stages operating in push-pull,
Radio systems
MODULATOR PM OR AM
CRYSTAL
POWER AMPLIr[ER DRIVER
Flo.
.
ANTENNA COUPLING ECu,PMENT
TO RECEIVER TRANSMITTER COMBINATICN OF BOTH
8.40 Radio communications transmitter — block diagram
Alitte one amplifier carries the positive half-cycles of the RE signal and the other the negative. The outputs of each of the two amplifier stages are connected to a orninon load which combines the two half-cycles to t2 the RE signal output shown. No current flows in t He stage unless a signal is present in addition to the onstant cut-off bias. This improves the stage efficiency to between 70 and 85%. Figure 8.41 (c) shows a typical transfer characteristic fkLf a Class C amplifier stage. In this case, the stage is biased by a multiple of the cut-off bias voltage value. large signal is applied to the input of the stage from the driver stage of the transmitter which results m the flow of RF signal pulses through the load of He Class C output stage. As shown in the figure, the pulses occur at alternate half-cycles of the input signal and are present for a period less than the time of a bill-cycle. The output load of the Class C stage is a parallel tuned circuit, tuned to the RF carrier wave. The Transmitter is designed so that the size of the RF pulses 1, large enough to contain sufficient energy to ensure tie tuned circuit continues to oscillate between pulses, arid contains sufficient harmonic information to carry !lie modulating information signal. Class C operation unproves the stage efficiency to between 95 and 98 07o. 1s can be seen from the transfer characteristic, a Class C staee operates on the non-linear portion of tHe characteristic. Therefore it requires only a small interfering signal fed back from the antenna to produce ii m‘ anted intermodulation products between the transmitted carrier frequency and the interfering signal. Figure 8.42 shows typical intermodulation charILIcristics due to the non-linearity of the Class C output 'rage of a transmitter at 150 MHz. The graph shows the level of third order intermodulation relative to the interfering signal level. As ■ otilci be expected, the level of the third order intermodulation decreases with an increase in frequency ,eparation between the source of intermodulation, i.e., he transmitted frequency and the interfering signal. The highest level of third order intermodulation for adjacent transmit channels, i.e., 12.5 kHz or ,
■•■■■1
RF MULTIPLPER
CO NT ROL L ED RF OSC.LLATCR
,
POWER AMPIJFIER
25 kHz channel spacing. This level of between —7 and —8 dB is sometimes referred to as the 'conversion figure' of 7 or 8 dB. Except where poor engineering practices have been adopted in the assembly of transmitters in the fixed station cubicle/cabinet, most intermodulation generation will be caused by coupling between antennas, either directly or via the feeder runs, or due to a combination of both — see Section 8.6 of this chapter on antennas. Care must be taken in the design of the coupling equipment (which interfaces the power amplifier and the antenna system) to reduce the signal levels which are received by the output stage from the antenna. Modern nuclear and large fossil-fuel power stations require a number of fixed stations to provide full radio cover of the power station. In order to use the same radio channel at a number of fixed stations, the transmitters are operated in a quasi-synchronous mode. This is necessary because it is usually not possible completely to confine the transmitted RF signal to one particular zone of the power station. A handportable user receiving similar signal strength RF carrier waves from two transmitters operating on the same frequency, would experience erratic reception of the radio message as he moved in the vicinity of overlap. This would be due to the addition, carried out in the handportable receiver, of all signals being received. The received signals would include direct and reflected signals from each of the transmitters. In some locations, the prominent signals from each transmitter would be out-of-phase causing a cancellation of signal, while elsewhere they would be in-phase. By off-tuning one of the signals by a very small amount, e.g., 2 or 3 Hz in 460 MHz, a quasi-synchronous mode of operation is achieved. The signals now add but result in a 2 or 3 Hz beat signal being produced which is sub-audible to the handportable user. In practice, a hissing beat is heard but it does not detract from the intelligibility of the message. In order to provide quasi-synchronous operation, it is necessary to have a very stable RF oscillator in the 699
Telecommunications
Chapter 8
STAGE CURRENT I I ; i +I
4'5
' FREO ,JENCY SEPARAT;ON
.,a) Class A Amplification
FIG. 8.42
STAGE 2 CURRENT
STAGE 1 CURRENT 4-1
—1
(b) Cass B Amplification
t
+1
NEGATIVE BIAS,V -4—
• I NPUT
CI Class C Amplification
700
•,
Effects of Class C non-linearity in the output stage of a transmitter
transmitter. A crystal-controlled oscillator is therefore provided with a frequency stability ageing rate of the order of 5 parts in 10 10 per day. The crystal used is contained in a temperature-controlled oven. The quasisynchronous systems marketed by Philips Telecommunications Ltd use a high stability drive unit Type HS400, a simple block diagram of which is shown in Fig 8.43. The latest transmitters being introduced for PMR systems use synthesising techniques. The crystal-conLOAD trolled oscillator is used to provide the stabilised RE generator but individual channel frequencies are derived digitally by means of multiplier and divider circuits. This approach has the advantage that one transmitter can be programmed to produce any one of 256 channels. 8.7.2 Fixed station receivers
STAGE CURRENT, I
F[G, 8.41
-
SCL:RCE
Amplifier classifications
The fixed station receivers used for power station radio systems are standard PMR receivers designed to operate at the particular band of frequencies allocated to PMR use. As explained in Section 8.7.1 of this chapter for fixed station transmitters, the VHF low band systems used in power stations employ single-frequency simplex AM operation and the UHF systems two-frequency simplex FM operation. The receiver equipment has to comply with the performance specifications issued by the Radiocommunications Agency of the DTI as described in the section on transmitters, i.e., MPT 1302 and 1326. Figure 8.44 shows block diagrams of typical AM and FM RF fixed station receivers. AM and FM systems both use similar antenna coupling equipment and RF amplifier sections. The AM oscillator and mixer stage connects the RF output of a local oscillator and the received RF signal in series to a non-linear device which produces three signals, f e , f c — f o and f c 1. 0 , e.g., for a received frequency (f,) of 461.5 MHz and a local oscillator
R adio systems
AND.7,0PAP4RATOR ASSEMBLY
78 .' 25 Hz PHASE ',OMPARAT,R
I
D.0
. = 1-"AT■ E
• I 0 _CF
7.R
LXII
FE r-No ASSEmoLy
3 , EPs
RE OPT
AF 01,,TaL„r
2! 5 MHz 52mI-Iz
• S62 SHz OR , ,;41
15 5 MHz • 5 MHz
'8' 25
2
7
P21-0 4 MHz
05 521 3333 Hz
195 3155 Hz Op ST 5c,53
RF OUTPUT Ir OR LI P ,
TT Az•S`l
I
E
R
0
Fici. 8.43
Block diagram or a high stability oscillator
AM RECEIVER
-.411■
acT.
ANTENNA COUPLING EOLAPMEN 7
CIF AMPLIFIER
RF OSCILLATOR AND MIXER
" IF AMPLIFIER
DETECTOR
SF AMPLIFIER
LIMITER AND DISCRIMINATOR
AF AMPLIFIER
LOCAL LOuDSPEAX ER CABLE , O REMOTE CON r7ROLER
FM RECEIVER
-
AE:En ■ ER AAN5mITTER '4AT:0N 50 n-1
.111•■■■
ANTENNA COUPLING ECuiPmENT
RF AMPLIFIER
FIG. 8.44
RF OSCILLATOR AND CONVERTER
MEMINIm.1
IF AMPLIFIER
•A■I
1■0/".
LOCAL LOUDSPEAKER CABLE TO REMOTE CONTROLLER
Radio communications receivers — typical block diagrams
frequency (f o ) of 472 MHz, two sidebands at 10.7 MHz and 933.5 MHz will be produced. The IF amplifier stage, which is tuned to 10.7 MHz, would select the Icimer sideband and amplify it. A similar result would be achieved if the local oscillator frequency f o were (f, — 10.7) MHz, i.e., 450.8 MHz. The two sidebands would then be 10.7 MHz and 912.3 MHz. This technique of converting the received RF signal to a lower intermediate frequency (IF) is called sirperheterodyning. The lower IF is more easily controlled within the receiver because stray capacitance has 40 times less effect on IF than on the equivalent RE. The cost of the electronic circuitry and screening is therefore considerably reduced. In modern RF fixed station receivers, a second stage 01 s uper - heterodyning is used to produce a second IF
of 465 kHz. The second IF is taken via another IF amplification stage to the detector, comprising a diode and RF filter which selects the AF signal for connection to the AF amplifier. When a SELCALL or CTCSS signalling system is used, these coded audio or sub-audio modulating signals are connected via bandpass filters to a tone detector circuit which will, on receipt of the correct signal code, unmute the AF output stage and connect the AF signal to the line interface or local loudspeaker. For quasi-synchronous working, the local oscillator output for each of the two oscillator/mixer stages will be derived from the same high stability drive unit described for the fixed station transmitter in Section 8.7.1 of this chapter. In addition to quasi-synchronous transmitter operation and multiple fixed station operation, a receiver 701
Telecommunications
Chapter 8 could be disconnected during transmission, this ma y not seem much of a problem. However, a switching solution would become very complex if five channels were involved. The problem is exacerbated by the need to ensure that each port is always correctly terminated to prevent reflections. Terminating loads would also be required, so that a disconnection/termination o f each receiver connection can be provided. Several years of research by suppliers like Sinclair Radio Laboratories have resulted in the development of sophisticated duplexers which are an improvement on resistive circuits. These are based on the use of compact 25 mm cavities, using either helical or coaxial line resonators. Figure 8.46 gives specification information and the frequency/attenuation characteristics for the MR356 duplexer suitable for operation in the 406/512 MHz UHF band. It can be seen that the maximum insertion loss from the transmitter to antenna is 1.5 dB and that the minimum receiver isolation at the transmit frequency is 75 dB, which are marked improvements on the 6 dI3 obtained when using a simple resistive circuit. Where the unwanted RF signal is separated from the wanted signal by a number of megahertz, as in two-frequency simplex systems, with the transmit and receive bands of frequencies separated by 5 MHz, coaxial filters or lumped circuit filters using discrete inductors and capacitors can be used. As the unwanted RF signal approaches within tens of kilohertz of the wanted signal, the rejection efficiency of these filters falls. Therefore, for coupling equipment which has to connect two transmitters to a common antenna, circulators have to be considered. A terminated circulator, also referred to as an isolator, is usually required when transmitters on adjacent
voting system is also used to determine which fixed station receiver is receiving the best signal from the mobile. The output from each receiver is taken to a common equipment which determines which receiver has the best signal to noise ratio. The best signal is selected and is connected to the remote controller. The latest receivers being introduced for PMR systems, like the transmitters, use synthesising techniques. The ,:r ■ stal-controlled oscillator is used to provide the stabilised RF generator but the individual channel frequencies are derived digitally by means of multiplier and divider circuits. The advantage with this approach is that one receiver can be programmed to produce any one of 256 channels, for example. 8.7.3 Antenna coupling equipment
Antenna coupling equipment is used to connect transmitters and receivers operating on different radio channels to a common antenna or antenna system. It is a very important part of modern power station UHF radio systems, where up to five radio channels can be in use at up to three fixed station locations. Figure 8.45 shows a simple resistive circuit that can be used to connect a transmitter and receiver to a common antenna. The resistor value of 16.7 ft is chosen to make each port of the three port system match the terminating equipment having nominal impedances of 50 Q. As can be seen from the figure, the disadvantages of this network are that only a quarter of the power from the transmitter is transmitted to the antenna and that a similar level of signal is connected to the receiver. If the resistive circuit were used to couple two transmitters to a common antenna, a similar situation would occur. Since the receiver in a simplex operation
= 16,70
R 16.70
TRANSMITTER OUTPUT — VIN CONNECTIONS
•
VIN
R = 16.711
• 1111
500
IMPEDANCE OF 500
RECEIVER °. 5 VIN INPUT IMPEDANCE
LOSS FROM TRANSMITTER TO ANTENNA = 6dB (INSERTION LOSS) LOSS FROM TRANSMITTER TO RECEIVER = 6d8 FOR A RESISTIVE COUPLING NETWORK THE FOLLOWING GENERAL EQUATION CAN BE USED TO DETERMINE R A- Z(n - 2/ WHERE Z NOMINAL IMPEDANCE OF EACH EQUIPMENT AND THE INPUT IMPEDANCE TO EACH PORT OF THE NETWORK WITH THE OTHER PORTS TERMINATED IN Z n = NUMBER OF PORTS ON THE NETWORK
FIG. 8.45 Resistive coupling circuit 702
500
5V
ANTENNA 4+1 IMPEDANCE
Radio systems
PORT 2 ANTENNA EEED
SPECIFICATIONS C.4 1 . 1 IT!ES 7_
S'PP ARA
5 MIN 50
N 1Hz
Sob MAX I 500 MAX Sob ON
WANTED OUTPUT FED TO ANT- ENNA
MIN 75cI2. AG 0 TC
',NWANTED ROWER ; RETL,EN NG
3 B N C OR TyPE N
POOR '.1500 LOAD ALL0'..../S REFLEC - EO POWER PC ENTER P .-",;7 - 3 AND CONT.NL:= ON TO POP.T THUS REDUC:Nc,S.OLA ThCN POSSIBLE DEVICE
32mm 156mm 229mm 1358 GRAMS
PORT 3 TEPMINAT ON LOAD DISSIPATES uN'v'iANTED ROWER FIG. 8.48
FREQUENCY MHz Fiti. 8.46
Duplexer characteristics
Lhannels, i.e., separated by as little as 12.5 kHz, are be coupled to the same antenna. A circulator is a nav,ive unidirectional device with three or more input or output ports. It usually contains a ferrite core throuQh which the RF signal injected into one port is Transferred to an adjacent port, while the other port Tor ports) are effectively isolated. Figures 8.47 and 8.48 ,how examples of three and four port circulators and .111 1,olator. 1 ,, shown in Fig 8,47, an RF signal entering port 1 ould emerge at port 2 only, an RF signal entering port 2 Gould emerge at port 3 only and an RF signal entering port 3 would emerge at port 1 only, i.e., in a cyclic order. in the direction of rotation indicated by the 3 PORT CIRCULATOR
4 PORT CIRCULATOR
PORT 2
PORT 1
RWARD LOSS --0 5 dB 0
EVERSE LOSS ^-30 dB
FIG. 8.47
Three and four port circulator configurations
PORT 3
Isolator configuration
arrow on the circulator symbol, an ideal circulator would have no losses but, in practice, a loss of the order of 0.5 dB will occur. In the opposite direction of rotation, an ideal circulator would pass no RF signal: in practice, a reverse loss in the order of 30 dB will be present. This unidirectional behaviour of a circulator is due to gyromagnetic effects in the ferrite core created by a high frequency magnetic field. For this reason, since moderately strong internal fields which have been adjusted for optimum performance are present in the circulators, the circulator should not be subjected to strong external magnetic fields or placed in close proxi mity to large masses of iron or steel. Isolators are three port circulators with one port terminated by its characteristic impedance. Thus, in the direction of rotation indicated by the arrow on the circulator symbol (Fig 8.48), an RF signal entering port 1 will emerge from port 2 while an unwanted or reflected signal entering port 2 will emerge at port 3 and be absorbed in the terminating load and no signal will pass on to emerge at port 1. Figure 8.49 shows an arrangement using isolators to reduce the effects of interfering signals between adjacently located transmitters. The rating of the load resistor connected to the third port has to be chosen on a worst case basis. Under normal conditions, spatial separation of the antennas and good installation of the antenna coaxial cables should result in an approximate isolation level of 30 dB, so the power in the load resistors will be about 30 dB down on each of the transmitter outputs. Under fault conditions, where one antenna may have fallen onto the other and become enmeshed with it, the power in the load resistor could be a combination of the transmitter output of the adjacent transmitter plus the reflected transmitted power due to an impedance discontinuity in the damaged antenna circuit. 703
Telecommunications
Chapter 8 •••
this chapter which deals with antenna systems. The 7 dB figure, sometimes referred to as the 'conversion figure' or 'conversion loss', i.; the level of third order intermodulation given in Fig 8.42. This represents the level of intermodulation, with respect to the interfering signal, for a frequency separation of 25 kHz which would be the case for two adjacent transmitter si g nals. The intermodulation level for adjacent chann e l transmitters, assuming a transmitter output of 25 IN (14 dBW), is given by: Intermodulation level = (Transmitter output) — (antenna/feeder coupling loss) — (conversion loss) = 14 — 30 — 7 = 23 dBW = 5 mW POWER IN R1 (OR R2) UNDER NORMAL CONDITIONS -30 dB RELATIVE TO Tx2 (OR Tx1) OUTPUT 2 POWER IN Ri OR R2) IF ANTENNAS MESH 0 dB RELATIVE TO 1x2 (OR Tx1} OUTPUT 3
POWER IN R1 IOR R2) IF OWN ANTENNA FAILS OR BECOMES A MISMATCH BY SNOW/ICE LOADING ETC 0 dB RELATIVE TO Tx1 (OR Tx2) OUTPUT NOTE; IN THE EVENT OF 2 OCCURING BOTH LOADS COULD BE AFFECTED
Flo. 8.49 Effects on termination power rating of isolator port
Figure 8.50 shows the improvement in isolation between two transmitters that can be achieved by using isolators. Figure 8.50 (a) shows the isolation that can be achieved by 0.6 m vertical spacing of UHF antennas operating at 450 MHz, as explained in Section 8.6 of
This level of intermodulation signal can produce a 0.5 ktV pd signal in a handportable, operating on the same frequency as the intermodulation, at a distance of approximately 75 m from the source of the intermodulation signal. Figure 8.50 (b) shows that an additional improvement can be made by using multiple isolators, with each additional isolator adding approximately 30 dB of isolation. Figure 8.51 shows an arrangement where three circulators are used. It should be noted that the rating of the load resistors connected to the terminated ports need not be the same. The isolator nearest the antenna would require a load resistor capable of handling approximately 25 W. The next load resistor handles —30 dB and the nearest load resistor to the transmitter —60 dB, both relative to 25 W, i.e., 25 mW and 25 gW respectively.
ANTENNA/FEEDER COUPLING LOSS
ANTENNA FEEDER COUPLING LOSS 30 dB
7
INTERMODULATION LEVEL -30 dB + (-7dE) ) RELATIVE TO 25 W =5mW
INTERMODULATION LEVEL -" -30 de + (-30dB) (- (--7dB) RELATIVE TO 25W 5d W
RANGE OF INTERFERENCE 5km
RANGE OF INTERFERENCE 75 m ADDITIONAL ISOLATION 30 dB
TRANSMITTERS 25W
TRANSMITTERS 25W NOTE: TRANSMITTERS ON NEARBY CHANNELS - WITHIN * 1%
Flo. 8.50 Improvements achieved by the addition of isolators
704
■■••"'
Radio systems
30 dB ISOLATON EEN ANTENNAS
X
WORST CONDITIONS
NORMAL CONDITIONS
TERMINATION TO HANDLE 25 W
- 30 dBb RELATIVE TO 25 W
TERMINATION TO HANDLE -30 dB RELATIVE TO 25W
TERMINATION TO HANDLE -30 dB +(-30d8) RELATIVE TO 25 W
- 60
de
RELATIVE TO 25W
- 90 dB RELATIVE TO 25W
25W FIG.
8.51
Use of multiple isolators
8.8 Lightning protection l ' diming protection is provided on all high, roofmounted, external antennas. The main protection is proN.ided by a bulkhead-mounted protector (high gain T!Pe LA-I or equivalent), located at the point where he antenna coaxial cable enters the power station building. The general precautions to be taken to reduce the effects of a lightning strike are listed in the following subsections,
8.8.1 Antenna systems 0 Use antennas having grounded elements and ensure
that elements are bonded to antenna mast.
• Provide a good earth directly below the mast and connect to the earth system of the building. • Solidly bond the outer conductor sheath of coaxial cable and the base of the mast using a proprietary grounding kit, ensuring that the bond is made watertight. • Ensure that the coaxial cable leaves the base of the mast using the sharpest bend permitted by the cable construction. Include as many sharp bends as practical between the base of the mast and the cable entry to the building. • Where possible, include a length of galvanised steel duct through which the coaxial cables can be taken. 705
1P• Telecommunications • Insert a lightning arrester in the coaxial cable where it enters the building (e.g., 'Hygain' coaxial arrester Model LA- t by Antenna Products Corporation, or equivalent). 8.8.2 Fixed station cubicle • Ensure that the antenna cable enters the fixed station cubicle at ground level and bond the outer conductor sheath to the single-point earthing of the cubicle, as near to the bottom of the cubicle as possible. • Connect a Etas discharge tube between the coaxial centre conductor and the cubicle earth at the entry to the cubicle. • Connect a gas discharge tube between the AC supply neutral and the cubicle earth as near to the bottom of the cubicle as possible.
8.9 Remote control systems The radio system controllers mounted on the control desks, or the table-top versions used at other control locations, can be supplied with a number of different facilities. The controllers used for power stations normally have the following controls and indications: Controls • Channel monitor
The controllers can use a number of types of Si g nailing between the controller and the fixed station, either directly or via a common equipment cubicic, depending on the complexity of the radio system. DC or AC signalling can be used, depending on the distances involved. For power station systems, AC signalling is now used so that isolating transformers can be interposed between each terminating equipment and the interconnecting multipair cable. The transforme rs and line protection units protect the equipment from the power surges, rise-of-earth potentials or circulating earth currents that can be experienced at a power station during faults on the high voltage system. Modern control systems, like the Philips Telecom M87, use toneburst digital signalling, supplemented by frequency division multiplex signals for keying transmitters or transmitting CTCSS or SELCALL tone signals. A simplified control schematic diagram based on the M87 control system is shown in Fig 8.52. 8.9.1
Operational description of the M87 control
system The local operator's controller is connected to the local operator's termination card in the M87 common equipment (CEQ) via a cable highway. The highway contains t wo pairs for send and receive audio speech signals, a pair for serial data out (SDO), a pair for serial data in (SDI), a core for the press to talk (PTT) transmitter keying control and a pair for power supplies derived from the CEQ, one core of which is used as an earth return for the PTT control. The in and out serial data is transmitted at 4800 Baud (bits/s), limiting the length of the cable highway to approximately 300 m. For distances greater than 300 m, the controller is converted to a remote operator controller by the addition of a MOdulator-DEModulator (MODEM) board and is connected to a remote operator termination card in the CEQ which contains a similar MODEM. The serial data is converted to frequency shift keying (FSK) signalling between the two modems operating at 300 Bauds. The PTT DC control signal is converted to 2970 Hz in the remote operator controller and mixed with the FSK and speech audio, which is connected to the 'send' pair of a two-pair cable between the controller and CEQ. The FSK and speech audio from the CEQ are mixed and connected to the controller 'receive' pair of the two-pair cable. By this method of converting all control and indication signals into voice frequencies and mixing them with the audio speech signals, it is possible to use amplified cable pairs for long cable runs in excess of 5 km. The serial data signals in both the 'in' and 'out' directions of local operator controller are taken via the local operator termination card to the SDI and SOD -
• Channel select • Talkthrough select (per channel) • Loudspeaker volume • Telephone handset volume • Loudspeaker or audible call select • Receiver voting by-pass Indications • Transmitter 'operated' lamp • Modulation lamp • Received call/busy lamp • Power on lamp • 'Channel on talkthrough' lamp It is generally felt that a simplified controller, similar to a telephone, would be more appropriate for power station use. Unfortunately, in recent years, the CEGB has not been able to make it financially attractive for suppliers to purpose build simplified controllers for power station use. With the proposed adoption of trunked radio techniques it is now more likely that, in future, the controllers will be replaced by telephones directly cabled to a radio telephone exchange connected in turn with the radio system through a common control equipment. -
706
Chapter 8
-
connections of a universal asynchronous receiver transmitter (UART), which is allocated to the controller in the operator's serial interface unit. Similarly the
•
Radio systems cnI and SDO of the modem lotrial data signals ' termination card are i n the remote operators - allocated to the remote op1 ed to the LIAR ...on neet tor RT con\ etts the serial data to parallel data flc ■ USC 011 the control processor unit (CPU) and ViCC versa. ,', ■ r.1 bus trol; ,Ind channel selections from the con\ll ,2 ,-, n are naken to the relevant UART as 'serial data od all indications from the CEQ and fixed radio .r taken from the parallel data bus via the are L ART as 'serial data out'. ▪ I he serial data in and out signals (SDI and SDO) leven-bit data word as shown in Fig 8.53 (a). .111 e o en-bit word corn prises a start zero '0' bit, cl data bits, a parity bit which can be either '0' or la give odd Ts parity, and a stop T bit. The odd parity is achieved by choosing a '0' or '1' for the raw \ bit to 'Ave an odd number of '1' bits when the and eight data bits are added together. This r,irity en,ibles a simple form of error detection check to be ,arried out at the receiving end. The serial data is ,onn.erted to the FSK signalling format shown in Fig ,;.51 (b) for remote operator controllers. The FSK ,1 nal5 comprise a 2295 Hz tone for logic zero and a Hz tone for logic one. The eleven-bit tone-burst ,1 preceded by a synchronising preamble of 40 ms at 2505 Hz. For a control, selection or indication message requiring only one eleven-bit data word, the word is repeated once and checked for correct reception. For a nc,aee which requires more than one eleven-bit word, I he first is repeated once followed by the remaining c io en-bit words of the message. The last two eleven-bit , Aords of the message form a checksum byte, which is 11 , cd for error detection. In order to understand the general signalling rinciples adopted for the M87 control system, a typical ,eleaion of channel 1 by a controller followed by the :ransrnission of a SELCALL to a mobile will be ,1e , cribed. f he 'select' button for channel I is first pressed on he controller. The eleven-bit code is then transmitted :rain the controller to the operator's serial interface tr.\ RT. A second UART in the serial interface will detect the operation of the interface UART and prepares the relevant parallel data address. On the next can by the CPU, the data and address will be loaded on the data and address bus. The CPU will decode the ,i..ILlress data, identify the associated operator termination card and decode the data bus message, which will , ordirm that the selection of channel 1 has been made. I he CPU, via the CMOS highway, will switch the luple.xer (MUX) on the addressed operator termina!on card to channel 1 and the MUX on channel termination card to the operator input, i.e., OP1 for :he local operator controller shown in Fig 8.52. On of this operation, the 'send audio' high"aY is connected from the local operator's controller Ihrough the operator termination card, channel 1 ter,
mination card, channel 1 remote control unit (RCU) to the two fixed station transmitters (ITX1 and ITX2) which use the same channel I frequency. Following selection of channel 1, the CPU will load the data messages onto the data bus and the operator's serial interface addresses sequentially onto the address bus; the 'channel I selected' indication will then be displayed on operator controller 1 and a 'channel 1 busy' indication on all other controllers. On receipt of the channel selected indication, operator 1 will press the SELCALL buttons to call the required mobile and press the send/key-transmitter button. The SELCALL code for the required mobile will be sent as an eleven-bit data word to the operator's serial interface where it will be loaded onto the address and data bus, under the control of the CPU, and transferred to the SELCALL serial interface. The interface will convert the parallel data to serial data using a UART associated with channel 1 and the serial data will pass to the SELCAL L. encoder in the channel 1 termination card. The encoder will convert the serial data to the necessary SELCALL VF sequential tones which will be passed, together with the transmitter keying frequency of 2970 Hz (originating from the local operator's termination card) and the CTCSS tone from the channel I RCU, to the two fixed station transmitters. A 2970 Hz detector in each transmitter will switch on the RF transmitters and the SELCALL sequential tones and the CTCSS sub-audible tone will modulate the RF carrier signal. When the relevant mobile receiver detects the correct SELCALL code, the audio output of that receiver will be unmuted and a call tone heard by the mobile user. The mobile user will press the mobile press-to-talk (PIT) switch and reply verbally with his name or callsign: a sub-audible CTCSS tone will also be transmitted. On receipt of the correct RF carrier and CTCSS tone, either one or both channel I fixed station receivers will receive the call. If both receive the call, the CTCSS detector in each will lift the mute on the receiver audio stage and pass the audible speech signals to the voting equipment. The better signal will be selected and the output of the voted receiver will be connected by the receive audio pair into the channel 1 termination card via the receive amplifier in the RCU. At the same time, an eleven-bit serial data word indicating the voted receiver will be passed from the UART to the FSK modem in the RCU. The FSK tone-burst, eleven-bit word will be decoded by the modem in the channel 1 terminating card and an eleven-bit serial data word passed to the channel serial interface, where channel 1 UART will convert it to a parallel data word. Under control of the CPU, the parallel data word will be passed, via the data bus, to the UART associated with operator I (OP I) in the operator's serial interface. The UART will convert the parallel data to serial data and this will pass via the cable highway to the local operator controller (0P1), where the voted receiver will be indicated on an LCD display. At the 707
▪ Telecommunications
Chapter 8
ME? COMMON EQUIPMENT CHANNEL ! TERMINAL CARD TE,ERADIO CONNECT ,TC1 TERMINAL CARD
Tc 41■■■ CP'
Tc 11
OEM
231 TE_EP•HCNE
M
X
FSK
I
nECAD!C CLIP ▪
MUX
4
MODEM
ri
AUDIO Tx
SELGALL ENCODER
C H2 CH3
SC N a: 7
OP , CABLE ,IGHWAY
LOCAL OPERATOR , CONTROLLER
awm.11.
CH1
AuDi0 SD IN OUT P1-I.
C0112
01-13
I
CHANNEL 2 TERMINAL CARD IC A U OP , 01.2
0P2 TERMINAL CARD j REMOTE 1 OPERATOR j CONTROLLER
4■••
2
1 PTT
MUX CONTROL
OP3
OP2
■ 1*■
AUDIO FSK IN OUT 2970 Hz P77
L
AUDIO R
CH2
SD ,N OUT ■•■
41.
PAiR CABLE
40010 -1'■
WIMP
- Earl
4
I■:1■!■■ MU X I.■•
■1111
CH2
•
CH3
MM.
CHANNELS TERMINAL CARD
AR307,1 A
Tc.
SO
AUDIO Tx
OP! OP
AUDIO
MUX CONTROL CH3
SD IN.OUT
SO IN OUT CENTRAL PROCESSOR UNIT
CHANNEL SERIAL INTERFACE
OPERATOR SERIAL, INTERFACE CONTROL
SO
DATA
LIART ■■I
()ART
ADDRESS
UART
CS-12 UART
SD
CH3 UART
SO
MI&
UAR7
.1•■•••••
PARALLEL DATA SUS SELGALL SERIAL INTERFACE
Fla. 8.52 Radio communications M87 control system — block diagram
same time, the audio reply will be heard on the loudspeaker. A similar procedure will take place for all controls, i.e., by-pass voting selection, talkthrough selection and calls to non-selective call mobiles, where the CTCSS tone will unmute the mobile receivers. 8.9.2 Operational description of the MotorolaStorno CAF2200 system The control system is based on the TE2200 terminal unit. The terminal unit comprises interface circuits for fixed stations, telephones directly wired to the radio system (DWTS) and PA(B)X tie circuits. The terminal 708
unit is connected to the fixed stations, DWTS and the PA(B)X by multipair cables. The fixed stations can be located in one or more locations as necessary to provide good radio cover of the power station. Each fixed station comprises radio transmitters and receivers, one of each per radio channel in use. The fixed stations operate in duplex mode, i.e : , they can receive and transmit simultaneously. This means that a continuous RF carrier is transmitted for as long as the channel is in use, even when no speech is modulating the RF carrier. The continuous RF carrier enables handportables and mobiles to identify busy channels when scanning for a free channel, following a
Radio systems
CPANNEL 3 IED 5 , A7ICA
HANNEL 3 ,
CL
xED STATIC-
T RECEyEg
COLPLING UNIT 71:ME CONTgOLLED SIGIkIALL,NG SYSTEM , -zyjE!,,LILT ■ F EOUEtiCY iil-liFY 'KEYING zxEP QESSQ TALX SIGNAL
\ \
:7
11` 47A E CALL SIGNALLING SYSTEM
, ER
Fr(
-
AS CHPONCUS =',ANSP.!IT -TER
8.52 (coned) Radio communications M87 control system — block diagram
PREAMBLE
¶1 BITS
(111.11111161 8 BITS DATA
. 8.53 N187 control system — serial data format
dial tone request being initiated by the user of the mobile or handportable. The DWTS have numeric keypads with star (*) and gate (#) buttons as found on modern pushbutton Mephones. Four alpha buttons (A to D) are also pro.ided for use with the special programming facilities
associated with the terminal unit. The DWTS use DTMF signalling to operate the terminal unit equipment and receive standard telephone ringing when called by the terminal unit. The DWTS are located at local control points, e.g., CCR, works control office and the power station reception desk. The star button (*) on the keyboard is depressed to obtain a dial tone. The handportable automatically searches for the first free channel and transmits the relevant DTMF code (see Fig 8.16 and Fig 8.54), On receipt of the DTMF code, the TE2200 stores the dial tone request until the CPU is free to deal with the call and simultaneously transmits a continuous carrier to busy the channel. When the CPU is free to deal with the call request, the TE2200 transmits an idle (R) tone. On receiving the idle tone the handportable transmits its 3-digit DTMF ID to the CPU. The CPU then repeats the ID back to the handportable in the form of a SSFC comprising a pulse of idle tone followed by each of three tones representing the handportable ID. On receiving the correct ID, the handportable transmits a pulse of acknowledgement (R) tone and simultaneously unmutes the loudspeaker. Receipt of the acknowledge tone by the TE2200 results in a dial tone being sent to the handportable. The handportable user then keys, on air, the required mobile or handportable ID or the access code for the PABX followed by the telephone number in DTMF signalling. On receiving the first DTMF tones, the CPU removes the dial tone and stores the received code. If the DTMF ID code is for a handportable or mobile, the CPU checks that the handportable is not already engaged on a call. If it is engaged then a busy tone is returned to the caller. If not, the CPU sends a preamble idle (R) tone to alert all quiescent handportables which are continually scanning the channels that an ID is about to be transmitted. All handportables lock-on to the channel and receive the subsequently transmitted ID. The calling handportable user also hears the ID which acts as a confidence tone following the keying process. If the called handportable is switched on and receives the ID correctly, it acknowledges the call by automatically returning an acknowledgement (R) tone. At the same time the AF section of the handportable is unmuted and the acknowledgement (R) tone is heard in the handportable at full volume, i.e., it by-passes the volume control. This acts as an alerting signal to the user of the called handportable indicating that an incoming call has been received. On receipt of the acknowledgement (R) tone, the TE2200 sends a ringing tone which is heard by both handportables at the volume control setting level which exists at each handportable. The called party answers the call by depressing the PIT switch. 709
Telecommunications
CALL .`,I
Chapter 8
T
A - ED
ALL C'LEA 9 ECI
i I
-
AL L I.I.:. ,3ILE• CIEII/7- 9CA
_ •.:--, '.-J7V---. x
7
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II _____I I__.1 _1 50
50
50
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I-1 = J-11 .1-7 11-1 •AD8,LE
L A A'
CAPPI• F.
4
VOSILE CALL
Bt.ocKE:1,-
Es.
':- k.. .NrJEL ENGAGED
!DLE TONE
DIAL TONE
SELECTIVE CALL
DIAL TONE
9 X 5:Irns "E RmI N A L E.T3 uLPI,IEN T
RLAIGNG 7.7:NE
SELECTEE CALL R
400
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1 26
5
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3s.
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9
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C
FIG. 8.54 Mobile-to-mobile signalling on the Motorola-Storno CAF2200 system
The TE2200 removes the ringing tone, connects the channel fixed station receiver AF output to the transmitter AF input and leaves the channel under the control of the system timers. If a call is completed before it is timed-out by the system timers, each party has to press the gate (if) button, which is equivalent to replacing the handset of a telephone, to release the call. The system incorporates four system timers:
If a handportable user tries to key without waiting for a dial tone or tries to do something on the system which is an incorrect operation, a 'don't do that' cadence of tones is transmitted from the TE2200. At first the operation of the handportable can be rather intimidating and people become a little overawed. However, after using the unit for a while most people regard it as being similar to a modern telephone.
• The channel activity timer circuit monitors the operation of PTT activity on the channel fixed station receiver. If no activity is detected for a preset period, a warning tone is transmitted which is heard on both handportables. If a PTT is not operated within 10 s then the channel time-out sequence is initiated, which transmits a time-out sequence of tones after another 10 s and immediately mutes the t wo handportable receivers and releases the connection.
Group calls
• The system dynamic timer circuit is activated when all but one channel are engaged. The timer timesout the longest established call 10 s after first transmitting a warning tone. • The minimum call timer prevents clear-down by the dynamic timer until after a preset minimum period selected by the customer in the range 10-60 s. • The maximum call timer clears down a call when the dynamic timer is not in operation, after a preselected period in the range 20 s to 5 minutes. 710
Two types of group calls are available on the system: (a) Hierarchical group calls — these are based on the three-digit IDs given to the handportables and mobiles. To enter the group call mode, the gate (#) key is pressed instead of the star (*) key to obtain a dial tone. • If a single digit is pressed followed by another gate (#), a hundred group is called, i.e., all handportables with the same first digit of their I Ds as the group digit transmitted. For example, a #4# would call the 400 to 499 group of handportables. • If two digits are pressed a tens group is called. For example, a #40# would call the 400 to 409 group of handportables. (b) Serial group calls use system number-pools in which a series of non-related three-digit numbers can be stored. To send a serial group call the user of a DWT, handportable or mobile merely keys-
Radio systems the number of the system number-pool followed in by the star (*) button. -11)breviated dialling number-pools can also be used to store ih e ,vstern ("TN numbers or short but frequently-used number in the system number-pool can nianners, ny d for ei: her serial o,roup calls or abbreviated c in hers • \l,rmarl port select
To manually select a channel port, the second display the hancloortable has to be selected by pressing mo de of on 'off button a second time. This is followed by the riessing the B button. The display changes to a C followed by four dashes. A four-digit security access code has to be keyed-in to 0es:upy the dashed positions on the display. The display then changes to CO1 indicating that ..hiannel I has been selected. I f another channel is required, this can be selected by 1,,j\,ing the required channel number and pressing B. Once in manual select mode, the group call or call ..alf facility can be used and the group of handportdhies locked-on to the selected channel. This provides ihe equivalent of an open channel and by-passes the c. stem timers. It is envisaged that this facility will be very useful during emergencies or during commissioning when an intricate test sequence is being carried out involving a number of dispersed commissioning engineers. Fixed station fall-back mode This Facility is software-driven in the fixed station. It enables a fixed station to be switched to act as a ,niasi-open channel on talkthrough. Any handportable or mobile user knowing the ne..cssary security access code is able to switch a fixed qalion to this mode of operation. Firstly, the handportable has to be switched to the manual mode of operation to enable the user to mandaily select the channel to be switched to fall-back mode. In the manual mode a telegram can be transmitted on the selected channel which switches the channel to talkthrough. Once the fixed station is switched to the fall-back mode, it transmits a preamble idle (R) tone to capture ail quiescent handportables and mobiles. This is folIt med by a,telegram to switch all the handportables and mobiles to the fall-back channel. The handportAt-Iles/mobiles then operate in the same manner as a :_lroup call where everybody hears and can speak to eryone else, i.e., equivalent to open channel operation on talkthrough. The Fixed station software repeats the handportable/ mobile capturing process at regular intervals to include newly switched-on radios or those that were out of range during the previous polling transmissions.
The fixed station can be switched back to normal by sending the relevant telegram from a handportable/ mobile in a similar manner to that used for switching to the fall-back mode. Other advanced features The system has a number of advanced software-driven features, some of which could be useful in emergencies. These features include: • Busy number break-in. • Channel congestion override. • Call enquiry and transfer. • Emergency calls to system manager or other designated DWT by keying 00 (without dial tone). • Call-back when free. • Abbreviated dialling. • Change of handportable ID using the keypad.
8.10 Handportable radiotelephone transceivers The handportable radiotelephone transceivers (handportables) used for power station radio systems have to comply with the following performance specifications of the Radiocommunications Agency of the Department of Trade and Industry (DTI): • For frequency modulated (FM), UHF and VHF equipment — MPT 1303 — Performance Specification for Angle modulated VHF and UHF radio equipment, incorporating integral antennas, for use in the Private Mobile Radio Service. • For amplitude modulated (AM) VHF equipment — MPT1304 — Performance Specification for Amplitude modulated VHF radio equipment, incorporating integral antennas, for use in the Private Mobile Radio Service. • For frequency modulated (FM) VHF and UHF equipment manufactured to the mobile specification MPT 1326 — Performance Specification for Angle modulated VHF and UHF equipment for use at fixed and mobile stations in the Private Mobile Radio Service. In addition to these requirements, the Joint Radio Committee (JRC) recommends that the maximum ERP from the handportable be limited to 0.5 W. For power station radio systems, this recommended value of RF power has been found to be too high. Control and Instrumentation equipment used in power stations is specified to withstand a radio field strength of 10 V/m for radio signals in the frequency bands between 20 MHz and 500 MHz (CEGB General Specification for Electronic Equipment — EES 1980). 711
Telecommunications
Chapter 8
Tests, supported by calculations, show that if a handportable having an ERP of 0.5 W is held within a distance of 0.5 m of sensitive C and I equipment, a field strength in excess of 10 V/m is produced (Fig 8.55). The variation in field strength given in Fig 8.55 is clue to different antenna gains associated with the different manufacturers. The calculated values are based on equations, which are only relevant for the far field region (see Fig 8.12). The far field follows a short transitional region at the end of the near field, which extends up to one-sixth of the wavelength from the antenna. As can be seen from Fig 8.12, inside the near field region the impedance of the wave changes rapidly from a constant value of 377 to a high or low wave impedance, dependent on the source impedance. The value of one-sixth of a wavelength for a UHF radio signal of 460 MHz will be of the order of 0.1 m which represents the origin of the graphs in Fig 8.55. These graphs cannot therefore be extrapolated into the area between the antenna and a distance of 0.1 m from the antenna, because of the rapidly changing wave impedance.
Tables 8.5 and 8.6 provide a schedule of antennas of different manufacture with the approximate gains as specified by the manufacturers. Using these antenna gains, the K factor shown in the table for each antenna has been calculated for both 0.5 W and 1.0W RF powers into the antenna. The K factor is calculated using Equation (8.10) from Section 8.5 of this chapter, where K = (30G 1 )+ The electric field strength (E) from an isotropic radiator is given by: E = (30P 1 ) I/R V/m where P 1 = transmitted power, W distance from radiator, m For an antenna of gain (G t ) with respect to an isotropic radiator, the equation becomes: E = (300 1 P)+/R = K (P,H.- / R V/m where K = (30G1)+ is a constant for a particular antenna arrangement. For new power station radio systems, the practice is therefore to restrict the RF power to the handportable antenna to 0.5 W. Even with this limitation, some
MOTOROLA KT220 1W 0 5W EFFECTIVE RADIATED POWER
STORNO AN865 AND MOTOROLA WHIP STORNO AN864 • RANK PL201
3 .2
3 3
05
-4-
PHILIPS TELESCOPIC PHILIPS COIL WHIP MOTOROLA SHORT HEL !FLEX 25mm
01
DISTANCE m
MEASURED RESULTS - -CALCULATED RESULTS
Fit:, 8.55 Field strengths from typical handportable transmitters at short distances, with 0.5 W into the antenna 712
handportables will exceed the 10 V/m field strength when operated within 0.3 m. For this reason, even lower output powers (of the order of 0.05 W) into the antenna are expected to be specified in future to eliminate any possibility of Radio Frequency Interference (RFI) to C and I equipment. This lower handportable transmitted output will have to be compensated by use of distributed fixed station receivers around the power station. With distributed fixed stations, power stations can be almost completely cOvered by these low RF signals without risk of interference to C and I equipment. This means that radio cover is not the problem it once was within a large modern power station. However, the presence of high audible noise in some areas of the power station is still a problem. Most handportables can be used with headsets and noise cancelling microphones or throat microphones. Unfortunately, unless staff have to work continuously in the noisy environment, they are not prepared to be cluttered with headsets, microphones, voice-operated switching boxes and the associated cable leads. In an attempt to find an alternative, handportables have been modified for use in power stations by drilling a small aperture in the lower face of the handportable which also contains the loudspeaker. An acoustic tube connects this aperture to a desensitised `electree microphone in the handportable. This enables the handportable to be held to the ear and operated like a telephone. An acoustic transducer fitted to the handportable produces a 110 dB sound pressure level alerting tone on receipt of the correct SELCALL code. These
Radio systems TABLE
8.5
Antenna schedule for transmitter output of 0.5 W e•-•- •
Field strength Gain with respect to dipole, dB
Effective radiated power, W
Spring helitlex AN 864 length 46 mm
- 8
0 079
19
Flexible whip AN 865 length 155 mm
- 6
0.126
Short heliflex (25 rum)
-12
X/4 Whip (pencil length)
Manufacture and type of antenna
At 0.1 m, V/rr,
At l m, Vim
Distance from antenna At 10 V/m,mm
1 K = (30G0T
1.9
190
2.79
24.5
2.5
260
3.52
0.03
12
1.2
123
1.76
- 6
0.126
24.5
2.5
260
3.52
Coil whip antenna
-10
0.05
15.5
1.55
150
2.2
Telescopic antenna (P5000)
- 9
0.06
17
1.7
170
2,49
0.5
50
5
500
4.97
0.02
10
,
.tlotorola Storno
Alotarola-Storno
Philips
Theoretical 0.5 W ERP from a 0.5 W handportable Philips HP IAN1 used in ERA tests
0
-14
TABLE
1.4
8.6
Antenna schedule for transmitter output of I W
Manufacture and antenna type
Gain with respect to dipole
Field strength at 1 m
ERP
Distance from antenna For FS = 10 V/m
1
K = (30G )2
.gotorola-Storno Spring befit-1ex AN 864 length 46 mm
- 8 dB
0.16
W
2.7
V/m
270 mm
2.79
Flexible whip AN 865 length 155 mm
- 6 dB
0.25
W
3.46 V/m
350 mm
3.52
-12 dB .
0.06
W
1.73 V/m
173 mm
1.76
-6 dB
0.25
W
3.46 V/m
350 mm
3.52
Motor°la-Storno
Short helillex (25 mm) X/4 Whip (pencil length) Philips
Coil whip antenna
-10 dB
0.1
W
2.2
V/m
220 mm
2.2
Telescopic antenna (P5000)
- 9 dB
0.125 W
2.4
V/m
240 mm
2.49
Theoretical 0.5 W ERP from a l. W handportable
- 3 dB
0.5
5
V/m
500 mm
4.97
W
modifications greatly improved the performance of the handportable in acoustically noisy areas.
8.11
Vehicle mounted radiotelephones The vehicle-mounted radiotelephones used for power -
station radio systems have to comply with the same performance specifications issued by the Radiocommunications Agency of the DTI referred to in the sections on fixed station transmitters and receivers, i.e., MPT 1302 and MPT 1326. A vehicle-mounted radiotelephone comprises: 713
Telecommunications • Vehicle boot-mounted transceiver. • Vehicle dashboard-mounted controller. • Vehicle-mounted antenna. The transceiver is a robust unit consisting of a receiver, transmitter and control interface. The transceiver is connected to the dashboard-mounted controller by a multicore cable which uses a plug and socket arrangement to interconnect the controller and transceiver. The plug and socket are held together using a retaining clip. The transceiver is connected to a roof or boot-mounted antenna by a coaxial cable. The coaxial cable is connected to the transceiver by a screwclamped coaxial connector. The vehicle dashboard-mounted controller comprises a loudspeaker and microphone, with controls for loudspeaker volume, squelch setting of the receiver (this is the muting arrangement which sets the level of RF signal required to lift the AF mute), channel selection and indicator. The vehicle antenna is either wing-mounted or roofmounted. The antennas used for power station radio systems are usually three-quarter wave for UHF and five-eighths wave for VHF and the Philips Telecomm GX Series of antennas in this range are shown in Figs 8.56 and 8.57. 8.11.1 Vehicle antennas
The efficiency of the quarter wave antenna is dependent on the mounting position, the better position being the centre of the vehicle roof, which acts as a good electromagnetic reflecting surface when it is a grounded metal roof acting as the common earth for the vehicle electrical systems. The metal reflecting surface has the effect of adding an electrical image of the antenna which, for a quarter wave antenna, would produce a transmit/receive characteristic equivalent to a half-wave antenna (Fig 8.37). The grounded metal roof is referred to as the 'ground plane' of the antenna. If the antenna is mounted on a non-metallic roof, a ground plane should be formed by sticking metal foil to the inside of the roof. The metal foil must be bonded to the earthed chassis of the vehicle and to the earth contact of the antenna coaxial cable. Mounting the antenna on the vehicle wing is a less efficient arrangement but may have to be accepted for vehicles with non-metallic roofs. Figure 8.37 (a) shows the effect of placing a conducting plane between the elements of a dipole antenna and Fig 8.37 (b) shows the equivalent circuit using a conducting plane. This plane is referred to as the ground plane for a monopole antenna. Each monopole has a feed point impedance of half that of the dipole because the voltage injected is divided between the two elements of the original dipole. Figure 8.37 (c) shows the free space radiation patterns of quarter wave monopoles over perfectly con714
Chapter 8 ducting ground planes of various diameters. The infinite ground plane shows a 3 dB gain over a dipole at zero degrees elevation angle, but any finite ground plane will exhibit a 3 dB loss. The 3 dB gain for an infinite ground plane is due to the fact that the same field is produced by an input voltage of half that required by a dipole across an impedance of half that of the original dipole. [t should be noted that the diameter of the ground plane for the 0.5 wavelength case shown in Fig 8.37 (c) must be 3.5 m for an operating frequency of 86 MHz and 0.6 m for 460 !v1Hz. Thus, to obtain the advantages of the ground plane reflection effect, the mounting position of the antenna should be chosen with care, 8.11.2 Noise suppression
In order to improve the signal to noise ratio of the receiver, it is necessary to suppress any electrical noise from the engine and ancillary electrical equipment. The levels of interference laid down by various countries are determined by the effect upon receiving equipment external to the vehicle, with the receiver located at a predetermined distance from the source. This can result in fields within the vehicle being too high for interference-free reception by sensitive equipment. Therefore, although the vehicle may be adequately suppressed for a conventional car radio/tape player, operation of communication type equipment in the VHF and UHF bands may require additional suppression. Assuming that the vehicle has been fitted with the basic suppression measures, the problem is to find the optimum location of the proposed receiving equipment and ascertaining the area of likely interference. The following precautions should be taken: • Antenna position is one of the most important points to observe during installation. The antenna and coaxial cable should be as far from the sources of interference as possible. The ground plane of the antenna must not be affected by interference currents. Any currents containing noise pulses, either conducted or induced, flowing in the ground plane will cause interference to be fed to the input of the receiver. • Cables for the radio equipment should not be run parallel with the electrical cable looms of the vehicle. • Particular attention should be paid to the battery supply for the radio equipment. Additional suppression may be necessary. • Offending electrical ancillary equipment on the vehicle will have to be individually suppressed following installation of the radio equipment. For detailed solutions to the various problem areas that can be experienced, refer to a specialised document, such as Philips Telecom Ltd Engineering Note TSP 427/1 Electrical Noise in Motor Vehicles.
Radio systems
1)
1
ELECTRICAL FREQUENCY RANGE 390-470 MHz GAIN 5dB MINIMUM RELATIVE TO QUARTER-WAVE ANTENNA WITH GROUND PLANE I MPEDANCE BANDWIDTH FEEDER
50 ohms 2% For 1 51 VSWR 4 5m URM76 IRG58 C/U).
URM43 OR FSJ1-50 LOW-LOSS
MECHANICAL ANTENNA ROD
2.5mm AND 1.6mm DIAMETER STAINLESS STEEL WIRE
TYPICAL VSWR CURVE TYPE GX450
FREQUENCY MHz 3X450H
GX450HS
GX450S
FIG.
8.56 UHF three-quarter wave vehicle antennas
8.12 Interference problems There are a number of sources of interference which have to be taken into account when designing radio `5, stems which use multiple RF channel operation. 8,12.1 intermodulation products The most prevalent source of interference is inter-
modulation products which can be produced in any non-linear impedance, given the right conditions. One of the possible sources of intermodulation has been referred to in Section 8.7.1 of this chapter. This is the output stage of the transmitter. Another can be the RF input stages or mixer stage of the receiver. As an example of the production of intermodulation, consider four frequencies a, b, c and d. 715
IP' Telecommunications
Chapter 8
ELECTRICAL FREQUENCY RANGE GAIN I MPEDANCE BANDWIDTH FEEDER
140-174 MHz 3db MINIMUM RELATIVE TO QUARTER-WAVE ANTENNA WITH GROUND PLANE 50 ohms L 2% FOR 1.5.1 VSWR
-
4.5m URM76 (RC 58/CAJ) OR URM43
MECHANICAL ANTENNA ROD
2 5mm DIAMETER STAINLESS STEEL
OX 150 ul 1.0 GX150CH
GX150TFH
60
1 62
164 166 168 FREQUENCY MHz)
170
Flo. 8.57 VMF five-eighth wave vehicle antennas
Third order intermodulation products can be produced when the frequencies bear the following particular relationships to each other: 2a —b=c or a+b—c ---d e.g., Let a = 456.25 MHz (Channel 25A fixed station transmitter) b = 456.325 MHz (Channel 27 fixed station transmitter) Then 2a — b = 456.175 MHz, which is the Channel 24 fixed station transmit frequency 716
Let a = 456.100 MHz (Channel 22A fixed station transmit frequency) b = 456.325 MHz (Channel 27 fixed station transmit frequency) c = 456.250 MHz (Channel 25A fixed station transmit frequency) Then a + b — c = 456.175 MHz, which is again the Channel 24 fixed station transmit frequency. To be able to select five channels without any third order intermodulation products being produced, it is necessary to have 12 regularly spaced. (e.g., 25 kHz
Direct wire telephone systems d) channels available. Channels 1, 2, 5, 10 and will not give rise to the production of third order interrnodulation products. For the power station UHF r frequencies, the third order intermodulation ho d o - ct; channels would be Channels 21A, 22, 23A, 26 rf ,i nd 27. fol1owin,2 Table 8.7 shows in greater detail the f no third order intermodula. crdilm channels 1 iwing lnierference. However it should be noted that if )ri (1\cs1 stations operate in the duplex mode, third order manodulation could arise when two adjacent fixed in ,t,itions are transmitting and a handportable on one tho channels is also transmitting.
Channel 25A = 456.25 MHz
race
TABLE 8.7 Operating channels having no third order intermodulation interference
ii red
3
6
10
Available channels
Operating channels having no third order intermodulation interference
4
1, 2, 4
7
1, 2, 5, 7
12
1, 2, 5, 10, 12
18
t, 2, 5, 11, 13, 18
26
I, 2, 5, 11, 19, 24, 26
35
1, 2, 5, 10, 16, 23, 33, 35
46
1, 2, 5, 14, 25, 31, 39, 41, 46
62
1, 2, 8, 12, 27, 40, 48, 57, 60, 62
ct a = 456.075 MHz b = 461.575 MHz = 456.100 MHz Hien a + b c = 461.550 MHz, which is Channel :I A mobile transmitter frequency. 8.12.2 Half IF interference
Mixer output will produce a difference frequency = 16.050 MHz or 5.35 MHz Note that 5.35 MHz has a second harmonic of 10.7 MHz which could also be produced, albeit at a lower level, in the mixer and passed on to the IF stage. Should the allocation of frequency channels to a power station make this form of interference possible, then the frequency for the local oscillator would be specified as 472.3 MHz.
9 Direct wire telephone systems
9.1 General details Discrete direct wire telephone systems (DWTS) are provided in power stations where direct and reliable means of speech communication is required between manned control points and the associated plant locations. The design of each DWTS takes cognisance of the following considerations: • Absolute reliability to ensure continuance of operation when all station supplies are lost. • Alternative to the PAX system and other DWTSs were practicable. • Cabling between equipment elements to be in shortti me fireproof cable to prolong operation during fire conditions in locations through which the cables are
routed. • Operation to be possible when control point or plant location equipment has been mis-operated, i.e., telephone handsets not replaced. • DWTS common equipment to be suitable for cubicle or control desk mounting. • The DWTS desk-mounted telephone concentrator panels to have the minimum of equipment mounted on them (Fig 8.58).
V, described in Section 8.7.2 of this chapter on r ,:ceivers, the first IF of the receiver is 10.7 MHz. A fixed station operating on Channel 22A will reti e the the mobile transmit frequency of 461.600 MHz. For the fixed station there is a choice of local oscillator frequency (f 0 ) to mix with the received signal to produce a difference frequency of 10.7 MHz:
• The equipment and control desk panels are based on modules of 10 DWTS extensions, expandable from 10 to 30 extensions. For more than 30 extensions a second control desk panel would be provided, extending the system to 60 extensions maximum.
f o = 461.6 + 10.7 = 472.3 MHz
For non-nuclear power stations it is the practice of
or = 461.6 - 10.7 = 450.9 MHz
the CEGB to provide a discrete DWTS radiating from each of the following control points:
Assume that Channel 22A fixed station receives a q_mal from Channel 25A fixed station transmitter at 456.250 MHz.
• Supervisor's desk - CCR.
,
f o = 472.3 MHz, or 450.9 MHz
• Each unit control desk - CCR. • Coal handling control desk - coal transport and stocking area (applicable to coal-fired stations only).
717
Telecommunications
Chapter 8
DIRECT WIRE TELEPHONE PANEL
13 II
'
•DW1 0W2_0W3OW4I0W51DW6 DW7IDW8DW9 DW I SUPPLY I 1 10 I FAA. • I
I
• ELEEEEEEEE is OFF SPEAK RECALL
N
1 NEON CALL INDICATOR
LA M P OW OW DW OW DW DW I DW DW OW 1 DW 11 12 13 I 14 15 16 I 17 18 19 I 20
bj i EE
13
OFF SPEAK RECALL
II 1\
TELEPHONE HANDSET
el
13
13 13 13
13
CT WIRE KEY
LAMP TEST
II
13
OW DW DW Ow OW OW DW DW DW 21 22 23 24 25 26 27 28 29
OFF SPEAK RECALL
FUSE
ALARM
OW'
30 I
B
_}
Flo. 8.58 DWTS concentrator panel and telephone handset
The additional DWTSs for nuclear stations are described in Section 14 of this chapter. The elements of the DWTS are: • Common equipment for cubicle or desk interior mounting. • Common equipment cubicle (if common equipment is to be cubicle-mounted) (Fig 8.59). • DWTS telephone concentrator with associated operator's handset at the manned control point (Fig 8.58). • Telephones in office locations. • Telephones with associated audible and visual calling units at plant locations. • Battery and charger. • Cabling. • Cable marshalling cubicle. 718
Block diagrams of the two types of DWTS, i.e., with desk-mounted and cubicle-mounted common equipment are shown on Figs 8.60 and 8.61. 9.2 Common equipment and common equipment accommodation The discrete common equipment for each DWTS is accommodated, where possible, in a single crate which houses the plug-in modules containing the DWTS equipment printed circuit boards (PCBs). There are three types of equipment module: • Module for four DWTS telephone extensions. • Module for switchboard telephone handset. • Module for crate alarms and crate power supplies. A typical DWTS having twenty telephone extensions would require one equipment crate housing:
Direct wire telephone systems
FIG. 8.59 DWTS common equipment cubicle 719
Telecommunications
Chapte r 8
1
rCONTROL DESK
20 WAY KEY & LAMP PANEL CONNECTOR
UNIVERSAL CONTROL UNIT CONNECTOR 48V DC FLEXIBLE SUPPLIES CABLE
CONTROL DESK TERMINATIONS
STATION ALARM PANEL
1.
2 PAIR
2 PAIR
_ 2,5 OR 20 PAIR
DESK TELEPHONE TO OTHER CONTROL DESKS
1
110VACOR 240V AC SUPPLY
20 PAIR
TOA 5 SEPARATE PAIR DIRECT WIRE 0 TELEPHONE SYSTEM
SHORT TIME FIRE PROOF CABLES
AUDIBLE AND VISUAL CALLING UNIT
5 PAIR WALL TELEPHONE
1
2-2 DUAL TELEPHONE 110V AC OR 240V AC SUPPLY
AUDIBLE AND VISUAL CALLING UNIT
—21A21 .410.• PAX TELEPHONE PAX
2 PAIR TO OTHER TELEPHONES
2 PAIR
21
1
WEATHERPROOF TELEPHONE
110V AC OR 240V AC SUPPL
AUDIBLE AND VISUAL CALLING UNIT
KEY El TELEPHONE HANDSET JACK - SOCKET TERMINAL BLOCK WITH TEST BUTTON
FLU. 8 O DWTS with desk mounted common equipment -
• Five, 4-DWTS telephone extension modules.
9.3 Plant telephones
• One switchboard telephone handset module.
DWTS telephones in plant areas are robust, heavy duty, weatherproof telephones with an associated audible and visual calling unit. Each DWTS telephone point is electrically connected to the DWTS common equipment by two cable pairs: one pair is used for speech and the second pair for signalling. The use of two pairs permits:
• One alarm and power supplies module. A DWTS having more than thirty telephone extensions would require an additional crate containing the additional telephone extension modules. 720
1 Direct wire telephone systems
I-
CONTROL DESK
ii
20 WAY KEY & LAMP PANEL CONNECTORS
LT
FLEXIBLE CABLE
Ti5 mETRE APPROX ) 2x20 PAIR
CONTROL DESK TERMINATIONS
7
DIRECT WIRE TELECOMMUNICATIONS ROOM
I
'1, 48V DC SUPPLIES
UNIVERSAL CONTROL UNITS CUBICLE CABLE TERMINATION CUBICLE J
2 PAIR TO MAINTENANCE AND COMMISSIONING
2 PAIR
STATION ALARM PANEL
TELEPHONE JACK SYSTEM
TO OTHER CONTROL DESKS
2 PAIR DESK TELEPHONE TOA 5 SEPARATE PAIR DIRECT WIRE-411--TELEPHONE —r SYSTEM
DUAL TELEPHONE 110y AC OR 240V AC SUPPLY
AUDIBLE AND VISUAL CALLING UNIT
5 PAIR WALL TELEPHONE
2 PAIR ' f_' 2 PAIR
AUDIBLE AND VISUAL CALLING UNIT 2 PAIR 2 PAIR
TO OTHER TELEPHONES
2.5 OR 20 PAIR SHORT TIME FIRE PROOF CABLES 110V AC OR 240V AC SUPPLY
2 PAIR
11-(311
PAX TELEPHONE
PAX
2 PAIR
ish
WEATHERPROOF TELEPHONE
110V AC OR 240V AC SUPPLY
AUDIBLE AND VISUAL CALLING UNIT
KEY
1: TELEPHONE HANDSET JACK SOCKET 0 rEPMINAL BLOCK WITH TEST BUTTON
FIG. 8.61 DWTS with cubicle-mounted common equipment
• Operat ion o f the audible and visual calling unit from he DNA, TS switchboard when the DWTS telephone e\ienion handset has not been replaced. • \udible confirmation at the DWTS switchboard that the audible and visual calling unit is operating.
9.4 Audible and visual calling units The audible and visual calling units are multi-purpose for use with one or two of the following telephones; PAX, PABX or DWTS, in any combination. The units are powered by 110 V or 230 V secure AC supply. 721
Telecommunications
Chapter 8 •••••
The audible device is an electronic sound transducer and the visual device is a rotating beacon. The AC supply voltage is wired to an internal transformer which provides an isolated 12 V AC supply for the beacon lamp and a DC supply (via an internal rectifier) for the beacon motor and the relay or solid state circuit. The DC supply is also used to operate the audible dc' ice \k hen he unit is used with a PAX telephone extension. \,1 hen LISCLI with a DWTS telephone extension, the audible device operates from the DWTS common 48 V battery supply via one pair of the telephone extension two-pair cable, when called from the DWTS telephone switchboard. This ensures that the audible device will also operate in the event of failure of the AC supply to the audible and visual calling unit. The outline of the audible and visual calling unit is shown on Fig 8.62 and the schematic diagram on Fig 8.63.
9.5 Common equipment location and battery supply The DWTS is entirely separate from the PAX system and provides an alternative means of speech communication to operational locations. To maximise diversity and security, the two systems are separately located and separately powered; the PAX in the power station MTR is powered by the MTR battery supply, and the DWTS common equipment in the power station ATR is powered by the AIR battery supply or the associated DWTS power equipment rack (PER) using a recombination cell 48 V battery.
10 Maintenance and commissioning telephone jack system The maintenance and commissioning telephone jack system (MCTJS) permits point-to-point speech communication between power station plant and also bet ween power station plant and the associated control room. The MCTJS provides conveniently situated speech facilities direct from power station plant. It is particularly useful during commissioning of the power station before other speech communication services have been provided. Two-pair circuits radiate from a central patching panel. Each two-pair circuit provides two speech channels paralleled to a number of four-pole telephone jack sockets mounted on, or near to, related station plant which requires occasional point-to-point communication, for commissioning, testing or operational purposes. Each pair of the two-pair circuit terminates at the central patching panel on a separate two-pole jack socket (Fig 8.64). Portable telephones and/or amplified headsets are used with the MCTJS for speech communication bet ween locations. The amplified headsets are provided 722
for use in noisy areas and for hands-free operation. Each telephone and headset is fitted with a connecting cord terminated on a four-pole telephone jack plug, having facilities to select either of the one-pair circuits when plugged into a four-pole telephone jack socket. When point-to-point speech communication is required between station locations not on the same com_ mon speech circuit, then patching cords are used o n the central patching panel (Fig 8.65) to connect th e unrelated speech circuits together. The MCTJS is extensively used during commissioning and is also used for operational and maintenance purposes when the convenience of speech communication to provide on-the-spot monitoring and performance of equipment is desirable. The MCTJS also provides useful direct speech links when long-time speech communication is required bet ween two or more locations without using other power station communication systems intended for short-time speech communication, e.g., the UHF radio system.
11 Siren system A single siren system is provided at non-nuclear power stations controlled in the station CCR from a manually operated siren control panel mounted on the supervisor's desk. The siren system is used to alert station staff regarding emergency conditions which may require the total evacuation of either all or part of the power station. A second siren control panel is provided in the gatehouse for alternative operation of the system. In addition to the siren system, other local emergency warnings are initiated by 'break glass' or equipment alarms in localised areas of the stations. Initiation and operation of local alarms is indicated at the CCR to make the control engineer aware of the situation. The CCR control engineer usually receives verbal information of power station emergencies via the PAX emergency telephone on his communications desk or is otherwise alerted by the station plant alarms. Sufficient sirens are provided to give total coverage of all zones of the station, both internal and external, with due consideration to ambient noise within the power station and the minimising of disturbance to nearby residents.
11.1 Station emergency zones For the purpose of the siren system the station is divided into eight zones. Any combination of zones may be , selected for operation of their sirens or, alternatively all station sirens may be operated by the ALL ZONES' control switch.
11.2 Emergency alarm signals Typical emergency alarm signals would be:
Siren system
ROTATING BEACON
TEST BUTTON SOUND TRANSDUCER
7_1
c.z ONf
R•V`JEL
S,PRLY ON LABEL
EARTH SOLT,
:S UPPLY ON — ,NOICATOR
GLAND PLATE FIG. 8.62 DWTS audible and visual calling unit
• Continuous signal mode — (in selected zones or all sLition zones): used for 'Station or Zones Evacuate' hen personnel are mustered in the open, e.g., fire, ilooding or a bomb alert when the suspect bomb is Inside a building. • Wailing signal mode (in all station zones); used or a 'Station Incident' when personnel are mustered indoors, e.g., for nuclear or chemical gas release or bomb incident when the suspect bomb is outside a —
• Intermittent short signal mode — is used as the 'Emergency over', or other instruction determined by the Station Manager.
11 .3 Control panels The CCR supervisor's desk siren system control panel is sho\\n on Fig 8.66 and the system block diagram
is shown on Fig 8.67. In addition to the 'siren operate' switches, there is a loudspeaker monitor switchable to microphones in each zone which enables the audible operation of sirens in the selected zone to be checked when a signal has been initiated at the control panel. An alarm display indicates when the power supply to the sirens and/or siren control equipment has failed. A pushbutton switch is provided on the panel to cancel the audible panel alarm after an alarm condition is received on the display. Another pushbutton permits visual testing of the alarm display light emitting diodes (LED). 11.3.1
Operation of system from power station
central control room controller
Operation of the system from the central control room (CCR) is carried out using the pushbuttons and rotary switch shown on Fig 8.66. The siren operation will be 723
▪ Telecommunications
Chapter 8 .■•••••••••
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Flo. 8,63 DWTS audible and visual calling unit — circuit diagram
automatically cancelled after three minutes, but reoperating the zone switch or turning the 'All Zones' rotary switch to the 'off' position will also cancel the operation. 11.3.2 Operation of system from gatehouse C ontroller
Reduced facilities are provided on the gatehouse controller. Only 'All Zones' operation of the sirens is possible for 'Station Evacuate', 'Station Incident' and 'Emergency Over' signals.
11.4 Equipment cubicle Fhe system equipment cubicle, connected to the control panel by multieore cables, is mounted remote from the desk in the auxiliary telecommunications room (ATR). The cubicle is the connection point for the system cables to the siren controller in the station CCR, to the siren control panel in the gatehouse, to the siren contactors and to the ATR 48 V DC supply distribution board.
11.5 Power supplies • Equipment cubicle and CCR control panel 724
The
equipment cubicle is located in the ATR. The power supply for the equipment cubicle and the power station CCR siren control panel is provided from the ATR 48 V battery.
• Contactors and sirens The contactor relay coils are operated from the ATR 48 V battery and the sirens are operated via the contactor contacts from a secure 110 V DC, 250 V DC, 110 V AC or 240 V AC power supply. The power supply at each contactor is monitored and loss of supply is alarmed on the power station CCR supervisor's desk siren control panel. • Gatehouse controller The power supply for the gatehouse controller is 48 V DC from a discrete battery in the gatehouse. 11.6 Cabling As stated in Section 4.3 of this chapter, the cabling for the siren system is in short-time fireproof cable to maintain the availability of the cable if fire occurs in the areas through which the cable passes. The cables radiate from a cable terminating cubicle mounted adjacent to the equipment cubicle in the ATR.
■
SUPERVISORS DESK
PATCHING BOARD
SE uLJ E NC E CONTROL
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IP Telecommunications
Chapter 8
TELEPHONE JACK SYSTEM PATCHING PANEL 1 GROUp 1 CIRCUITS
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• Two telephone concentrator panels (for concentrating telephone circuits onto one panel) with plu g _ in pendant telephone handsets.
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• One BT ex-directory, out-of-area exchange line telephone. • Two PABX telephone extensions, one having night service transfer facilities. • One pendant telephone to off-site emergency serv
ices.
• One non-busy emergency PAX telephone circuit having digital display of the telephone number of each calling PAX telephone. • One station siren control panel with loudspeaker for monitoring the operation of sirens in each zone of the power station.
0 v
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TWO WAY PATCHING CORD
The CCR supervisor's desk will have panel space for the following equipment:
PATCHING PANEL JACK SOCKETS } HIGHWAY 1 } HIGHWAY 2
• One radio system controller, having access to all channels of the station UHF personal radio systems. • One radio paging controller. • One grid control emergency VHF radio controller. • One DWTS switchboard. • One grid control telegraph for receiving visual instructions from the grid system control. • One actual load display and grid control instructed load display for each generator. • One civil defence warning receiver (where specified). • Visual display units (VDUs) for station services transmission, etc.
F. 8,65 Layout of N1CTJS central patching panel
12 Central control room supervisor's desk The power station central control room (CCR) supervisor's desk is the main location in the power station from which station operation is controlled. Reliable and alternative means of speech communication arQ required from the supervisor's desk to all power station locations, to station roving staff, to the grid system control centre, to the public emergency services and to the PSTN. Reliable means of alerting all station staff are required from the supervisor's desk when station emergencies occur. Control and instrumentation equipment to provide visual information of power station performance and visual information/ instruction of system operation requirements is also installed on the supervisor's desk. 726
The two telephone concentrators provide duplicated access to PAX telephone extension circuits, PABX telephone extension circuits (when the concentrator is British Approvals Board for Telecommunications (BABT) approved), grid control telephone extension circuits and also MCTJS circuits. A waiting amplifier with loudspeaker is provided on each concentrator to permit incoming telephone calls to be heard without using the telephone handset. Each telephone concentrator is powered by a separate 48 V battery supply to reduce the probability of simultaneous loss of both concentrators. Secure and alternative AC supplies are provided for desk equipment operating on AC to reduce the probability of simultaneous loss of equipment.
13 Nuclear power station requirements 13.1 Specific requirements for nuclear stations Nuclear power stations require telecommunication equipment and services additional to that required for
Nuclear power station requirements
O
ZONE I POWER SUPPLY FAIL
Q
ZONE 2 POWER SUPPLY
G
ZONE 3 POWER SUPPLY FAIL
O
ZONE 4 POWER SUPPLY FAIL
FAIL
ZONE 5 POWER SUPPLY FAii_ ZONE 6 POWER SUPPLY ; O ZONE 7 POWER SUPPL cAiL ' 0 ZONE 8 POWER SUPPLY EA!L
EXTERNAL AREA POWER SUPPLY FAIL CONTROL OFF TIMED OUT UNIT 7 EQUIPMENT SUPPLY FAIL UNITE EQUIPMENT SUPPLY FAIL
ZONE MONITOR
ZONE 1
ZONE 2
ZONE 3
ZONE 4
ZONE 5
ZONE 6
ZONE 7
ZONE 8
ZONE 1 ZONE 2 ZONE 3 ZONE 4 ZONE 5 • ZONE 6 • ZONE 7 ZONE 8
STATION INCIDENT
FIRE ZONE EVACUATE OPTIONAL I + SIGNAL ALL ZONES I [ 1F REQUIREDI
OFF
STATION EVACUATE
I
i
—OPERATE
OPERATE—
i
ALL ZONES
FIG. 8.66 Siren system — central control room controller
rossil-fuel power stations. Telecommunication systems must be adequate to cater for postulated non nuclear and nuclear emergencies which may arise during the +‘orking life of the power station. Provision of telecommunications facilities and services in the nuclear areas is often difficult because of their physical isolation from the conventional plant areas of the power station. Radio communication, v, hich is required in all areas of the station, presents particular problems because of the civil construction 0 1 the nuclear areas including steel-reinforced concrete, steel containment of equipment and the tunnels. -
Nuclear power stations have emergency centres which are brought into operation during nuclear emergencies on the site and require access to telecommunication systems. These are detailed in Section 13.4 of this chapter.
13.2 Public address systems It is current CEGB policy to provide a public address system in new nuclear power stations but not in new non-nuclear power stations. A duplicated public address system is provided for nuclear power stations because it is essential to acquaint all on-site personnel 727
-
Telecommunications
Chapter 8
,
1
,
-
ZONES
4
FIG. 8.67 Siren system — block diagram
immediately of action to be taken should a nuclear emergency occur. A duplicated public address system, having parallel operation of both separate systems, ensures maximum availability of equipment and should provide good overall intelligibility of verbal instruction and alarm tones in all areas of the power station. The loudspeakers of each separate system are interspaced, each system providing total cover of all locations, thereby ensuring total station cover if either system fails. There are two auxiliary telecommunication rooms ( ATRs) for a two-reactor nuclear power station. The equipment cubicles for each public address system are located in separate ATRs to minimise the possibility of loss of both systems in the event of a local fire. In locations where the ambient noise level can vary from high to low, such as the turbine hall where noise level depends on whether or not the turbine-generators are running, noise volume sensors monitor the ambient noise level and remotely adjust the volume of the public address amplifiers serving the location to the appropriate level. Facilities are provided to check the individual operation of the large number of loudspeakers. This is done by selecting the loudspeaker omnibus circuits to be tested and transmitting a 'click' sound on the circuit. The audible operation of each loudspeaker on the circuit may then he checked. When the station siren system is operated, the public address system will enhance the siren sound by a simulated siren sound generated in the public address system control equipment, which is triggered and synchronised by signals from the associated station siren system. Figure 8.68 shows the block diagram of a nuclear power station duplicated public address system. 13.2.1 Power station zones
For the purpose of public address broadcasting (and 728
also for operation of the sirens via the siren system described elsewhere), the power station is divided into eight internal zones and one external zone. This facility may be used to minimise interference by public address messages in zones of the power station not affected. 13.2.2 Controllers
The public address system at a typical AGR power station is controlled from: • The CCR supervisor's desk. • The Emergency Control Centre (ECC). • The Emergency Indications Centre (EIC). • The power station telephone operator/receptionist. The ECC is staffed during a nuclear emergency to take over executive control of the emergency, leaving the CCR to carry on controlling the operation of the power station and/or shutdown of the reactor(s). The EIC is staffed to supervise the shutdown of the reactor(s) in the event of the transfer of control, during an emergency, from the CCR. The EIC has indications of the reactor status but no direct reactor controls. Each controller has a hands-free microphone and may broadcast to any or all zones by the operation of appropriate zone switch, or to all locations by operation of the ' All Zones' switch (Fig 8.69). A monitor
loudspeaker on each controller, relays messages originating from any of the other controllers and the indication lamps also light to show the zone of the power station to which the broadcast is being transmitted. Each zone switch has three positions, i.e., off/speak normal/speak emergency, the last named position generates an 'emergency' signal to precede the message.
Nuclear power station requirements
A.NY TELE,-,Cmt.15 ROOM '
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■■•■••••1.
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_
L FIG. 8.68
Public address system duplicated for a nuclear power station — block diagram
Each controller operates on 110 V AC uninterrupted rower supplies, 13.2.3 Common equipment
The equipment of each public address system is located in a different ATR from its associated duplicated , ■ stem to minimise the risk of loss of both systems. Each system is connected to a different 240 V AC dieselbacked supply. Each common equipment comprises a control cubicle containing equipment to interface with the controllers, le el and tone controls, pre-amplifiers, etc. Other cubicles contain the 100 W amplifier modules (or other unit power size) to power the 50 V or 75 V lines of the loudspeaker distribution network. A cubicle is also used io terminate all the loudspeaker distribution cabling. Each amplifier module has a volume control, tone control and output indicating device or meter for Individual adjustment. Figure 8.70 shows a typical layout of the control cubicle and amplifier cubicles. 13,2.4 Loudspeakers
Loudspeakers are re-entrant, unidirectional or bidirectional, cabinet or ceiling type to suit the local conditions.
13.3 Siren systems As with the station public address system, it is CEGB
policy to provide a duplicated siren system for nuclear power stations because it is essential to acquaint all on-site personnel immediately of action to be taken should a nuclear emergency occur at the station. A duplicated siren system, having paralleled operation of both separate systems ensures maximum availability of equipment to provide good overall coverage of all areas of the power station. The sirens of each separate system are interspaced, each system providing total coverage of all locations thereby ensuring total cover of the power station in the event of the failure of either system. The equipment cubicles of each siren system are located in separate ATRs in a similar way to the public address system to minimise the loss of both siren systems in the event of a local fire. Figure 8.71 shows the block diagram of the system. 13.3.1
Siren signals
In areas of very high ambient noise, the siren sound is supplemented by discrete beacons to indicate the particular siren signal. Three siren signals are generated by the system: • Continuous signal mode (with operation of associated red beacons) 'Station or Zone Evacuate' This signal is used for fire, flood or bomb alert when the suspected bomb is located indoors. Personnel muster at outdoor muster stations. 729
Telecommunications
Chapter 8
OAPO:OD mICHOPHONE
A No.1 SIREN SYSTEM
No.1 ' SYSTEM I FAULT
No .2 SIREN SYSTEM
I
No 2 SYSTEM FAULT
ZONE 1
ZONE 2
ZONE 5
ZONE 6
LAMP TEST
I
ZONE
ZONE
I
3
4
ZONE 7
SYSTEM 1
POWER ON
MONITOR ZONES
ZONE 8
SYSTEM 2 ALL ZONES
SPEAK NORMAL
0 POWER ON
L SPEAK EMERG
*PUSH ON PUSH OFF ILLUMINATED PUSH BUTTONS 0 NON-LOCKING ILLUMINATED PUSH BUTTONS A ILLUMINATED LAMPS ONLY Z LEDS-LIGHT EMITTING DIODES
Fic,. 8.69 Public address system controller panel layout
—
duplicated for a nuclear power station
• Waiting signal mode (with operation of associated yellow beacons) 'Station Incident' This signal is used for radiation gas release, chlorine gas release or bomb alert when the bomb is located outdoors, e.g., in a car parking area. Personnel muster at indoor muster stations.
The siren system at the most recent nuclear power station is controlled from:
• Intermittent short period on signal mode 'All Clear or Stand-down'
• The supervisor's desk in the CCR. • The EIC communication desks.
730
This signal is an option available for use as determined by the Station Manager. 13.3.2 Controllers
Nuclear power station requirements
FI(J. 8.70 Public address system — layout of equipment cubicles — duplicated for a nuclear power station 731
Telecommunications
Chapter 8
1
rAtjx.q_,ARY TELLCT,UN'AIS ROOM
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—
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SIREN CONTROL DIVERT SWITCH
r
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ROUTES
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DESK? SIREN SCNTROL
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2
OTHER = FIRE
ROUTE 2
I
CONTACTOR UNIT ETC. AS SYSTEM
ZONES
L
FIG. 8.71
-----------_1
REPEATS FOR OTHER ZONES
Siren system — duplicated for a nuclear power station
The CCR supervisor's desk controller has facilities for sounding the continuous signal (for 'Zone Evacuate' at nuclear stations) in any or all of the eight zones of the power station, with audible monitoring of the siren operation. The CCR supervisor's desk controller also has facilities for operating all power station sirens by operating the 'All zones' switch to 'Station Evacuate' (continuous signal) and 'Station Incident' (warbling signal). The controller panel layout is shown on Fig 8.72. The controller in the EIC can divert the control of the power station sirens to the EIC by operating a switch on the EIC controller. An indication that the control has been transferred is given on the supervisor's desk controller. Only the 'All zones' Station Evacuate' and 'Station Incident' signals can he initiated from the EIC controller. 13.3.3 Common equipment
The common equipment of each system, in addition to being located in a different AIR, is also connected to a different 48 V battery supply from that of its associated duplicated system to minimise the simultaneous loss of both systems due to a common mode failure. 13.3.4 Cabling and power supplies
The cabling of each siren system is segregated and 732
L
the power supplies to the siren contactors and sirens in the same area are from different sources to minimise the risk of simultaneous loss of both systems. 13.4 Emergency telecommunications 13.4.1 Nuclear incident
A nuclear incident at a nuclear power station would be reported to the CC R. The supervisor's desk in the CCR becomes the focal point in dealing with the initial stages of the emergency. Action would be taken from the supervisor's desk to initiate the emergency procedures and to inform all on-site personnel of the incident. The external emergency services are also informed. The CCR follows the nuclear incident procedures until the on-site ECC is staffed and operational to take over control of the situation, thereby releasing the CCR to concentrate on the operational aspects of the plant unaffected by the incident. Telecommunication services are diverted from the power station to each emergency centre as it is activated. 13.4.2 Emergency control centre (ECC)
All CEGB nuclear stations have an ECC which is usually located in the administration building. The ECC is equipped with telecommunication equipment which
N uclear power station requirements
ZONE 1 TURBINE HSE - UNIT 7 & 8 ZONE 2 REACTOR BLDG 7 & 8 ZONE] ESB 8A. 88. DIESEL HSE A ZONE I ESB 7A 7E1_ DIESEL HSE B ZONE 5 FEB 70 70 DIESEL HSE
O O O O
ZONE 1 POWER SUPPLY FA:L ZONE 2 POWER SUPPLY Fan_ ZONE 3 POWER SUPPLY Eal ZONE 4 POWER SUPPLY Pa L
O O
ZONE 5 POWER SUPPLY EaIL ZONE B POWER SUPPLY FA , L
O I 0
ZONE 7 POWER SUPPLY FAIL ZONE 8 POWER SUPPLY FAIL
ZONE E.: 553 3C 3D DIESEL F-ISE 0 ZONE 7 ADMIN BUILDING ZONE 3 C,WPR ABC. MISC BLDS
3 EX AREA POWER SUPPLY FAIL CONTROL OFF-TIMED OUT 0
AUDIBLE MONITOR OF SELECTED ZONE
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6
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CONTROL ON • SYSTEM I
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Fft-,. 8,72 Siren K
system —
CCR
controller panel
actk ated when the ECC is staffed during a nuclear incident and the telecommunication services serving the power station are diverted to the ECC when it is nperational. The ECC provides co-ordination with the cnierQency services and takes over this responsibility during the incident to enable power station staff to .oncentrate on dealing with the incident itself. ,
layout — duplicated for a nuclear power station
13.4.3 District survey laboratory (DSL)
All CEGB nuclear power stations have a district survey laboratory (DSL), which is a separate building tither within the site boundary or within a radius of 1.6 km of the power station. The main function of the DSL is to house the nuclear health physics laboratory of the power station. It controls routine health physics 733
Telecommunications sampling checks of the surrounding area and analyses the samples brought in during routine checks. The DSL also serves as a secondary emergency control centre (SECC) should it not be possible to use the ECC in the event of fire or nuclear health hazard: facilities exist to divert emergency telecommunication facilities to the DSL from the ECC. During a nuclear incident when the ECC is operational, nuclear health physics staff would occupy the DSL and provide assistance to the ECC as required. If there are two nuclear power stations on the same site, each station would have its own ECC but would use a common DSL for both normal health physics work and for nuclear emergency services. 13.4.4 Operations support centre (OSC) In a nuclear emergency, an off-site operations support centre (OSC) is activated. The purpose of the OSC is to provide a focal point for the dissemination of information in respect of the nuclear incident to the general public and the media at a location remote from the power station, thus minimising the nuisance and disruption in the area surrounding the power station due to the public and media seeking information and interfering with the mobility of the emergency services. The police and other nominated services would also be in attendance at the OSC. Telecommunication services, including an on-site PABX are brought into service at the OSC. Designated telecommunications circuits serving the power station and the station emergency telecommunication centres ( ECC, DSL, etc.) are diverted to the OSC to provide direct telecommunication circuits to the BT PSTN, the emergency services, to CEGB national emergency centres and also to the power station. A block diagram of the circuits for providing telecommunications services during a nuclear incident at a power station site is shown on Fig 8.73. 13.4.5 Radio services for a nuclear emergency
On-site UHF radio
During a nuclear emergency, good speech radio communication is required to and between roving emergency staff on the power station site. To enable this to be provided by the UHF radio system, the control of one or more of the power station operations or maintenance radio channels is taken over for such emergency use.
Off-site VHF radio
The two VHF channels allocated for nuclear purposes will be actively used during an emergency. One channel is used to communicate with handportables carried by nuclear emergency staff who may be operating on the power station site or off-site. VHF mobile radios fitted into power station vehicles will also use this frequency. The second of the two VHF channels is a nuclear 'general channel' which is used by other nuclear organisations, such as the United Kingdom Atomic Energy 734
Chapter 8 Authority (UKAEA), who would be involved durin g an emergency. The VHF channel would enable corn. munication with the UKAEA vehicles. Control of th e nuclear channels would be available from the CCR, ECC, and the DSL. Additionally the CCR and ECC would have access to the CEGB Grid Control eme r _ gency VHF channel. The arrangement of the VHF fixed stations and VHF fixed station controllers is shown on Fig 8,74.
14 Pumped-storage power station requirements pumped-storage power station having electricity generating plant and EHV transforming plant underground presents problems in providing good communi. cation throughout the power station. The telecommunication speech systems provided for a pumped-storage station are influenced by the constraints of the station location and design. The systems outlined in this section are based on those provided to meet the needs of a CEGB 1800 MW pumped-storage power station at Dinorwig, North Wales, where the main plant is located in a cavern created inside a mountain, the composition of which is largely slate. Telecommunications cover, particularly for speech communication, is required in the internal and external areas of the power station which basically are: A
• Underground plant areas (including access and interconnecting tunnels, 400 kV switching station and 400 kV cable tunnel). • External upper water reservoir area and tunnels. • External lower water reservoir area and external administration building. • External roads to reservoirs and gauging stations. Sufficient diversity of telecommunications systems and equipment is provided to enable telecommunications facilities to be available during any credible failure of plant, including loss of all electricity supplies within the underground areas of the power station. Possible rises of earth potential between discrete areas of the power station, during faults on the 400 kV electrical system at Dinorwig, were likely to be high because of the slate enclosure of the power station: therefore the telecommunication circuits connecting the discrete areas of the station were fitted with isolation barriers. In addition, the postulated rise of earth potential during the above condition between the power station and the local village (within the boundary of which was the BT telephone exchange serving the power station) was high as a result of the slate composition of the locality. All telecommunication circuits were therefore fitted with isolation barriers (see Fig 8.7) to minimise the transfer of the rise of earth potential to the off-site BT telephone cables serving the power station.
Pumped-storage power station requirements
OUT OF AREA EXCHANGE EINE
1 7,E
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EMERGENCY SWITCHBOARD
JABS SEqi , CE E ON
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EMERGENCY COMMUNICATIONS ---• HANGEOvER SWITCH EME.GE`IC CCMI.ILNCX ;Ns CHA',GE=.. ER
OPERATIONS SUPPORT CENTRE EMERGENCY COMMUNICATiONS CHANGEOVER SWITCHES
NUMERAL INDICATES NUMBER or CIRCUITS
2 DISTRICT SURVEY LABORATORY
EMERGENCY COMMUNICATIONS CHANGEOVER SWITCHES
TO ELEC71C , T , SUPPLY :NODSTRY CORPoRArE TELER.ONE NETWORK
EMERGENCY PABX
=La
EX DIRECTORY EXCHANGE LINE
'2
DSL EXTENSIONS
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I
FK., 8.73
EMERGENCY COMMUNICATIONS CHANGEOVER SWITCHES
Nuclear power station on-site emergency telecommunication circuits to off-site locations
The various telecommunications systems provided Dinorwig are listed below: • Private automatic branch exchange (PABX). • Private automatic exchange (PAX). • Radio paging system. • Radio system. • Sound-powered telephone systems. • Maintenance and commissioning telephone jack systern.
• Siren system. • Grid system operations telecommunications system.
14.1 Private automatic branch exchange The PABX in the above-ground station administration building provides telephone communication facilities and access to the BT PSTN and also access to the BT PSTN for a limited number of locations in the underground areas of the power station. The PABX provides the same facilities as for a conven735
Telecommunications
Chapter 8
E X E . ., ,,sL
r-
7
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EE
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CL
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F[ci. 8.74 VHF radio fixed stations and controllers for a nuclear power station
tional power station, as detailed in Section 6 of this chapter.
14.2 Private automatic exchange
Radio paging coverage of all power station areas, and the roads to the external power station locations, is provided by overlaying the radio paging signals on two channels of the power station three-channel radio system and taking advantage of the extensive antenna system of the power station radio system detailed below.
The PAX provides general telephone communication to all areas of the underground locations and the above-ground external areas of the power station not requiring access to the 13T PSTN. The PAX provides the same facilities as for a conventional power station, as detailed in Section 5 of this chapter. Ten nominated FAX telephones located at important operational locations, in addition to having normal FAX facilities, have the option of directly calling a 10-way direct wired telephone switchboard on the communications desk in the CCR by the operation of a pushbutton on the telephone. The communications desk may also directly call any, or all, of the nominated FAX telephones from the 10-way direct wired telephone sNiitchboard. The facility operates independently of FAX and is available for use when the PAX is out of service. This facility provides a dual-purpose limited direct wire telephone system.
14.4 Personal radio system The personal radio system uses seven fixed stations. Each fixed station has one or two radio channels to provide speech communication, between the controllers in the CCR and the station administration building, to roving station staff in all external/internal areas of the power station and along roads to external station locations where handportable radiotelephones and/or vehicle-mounted radiotelephones are used. The 400 kV switching station and 400 kV tunnel radio system use one fixed station controlled from a controller in the 400 kV switching station and from the CCR. The system operates on VHF rnidband and is amplitude modulated.
14.3 Radio paging system The radio paging system generally provides the same facilities as for conventional power stations, as detailed in Section 7.3 of this chapter.
The antenna system for the multichannel radio system comprises approximately 9 km of radiating cable (leaky feeder) supplemented by conventional antennas, which provides cover for the labyrinth of tunnels and rooms in the underground areas of the power station. Con-
736
14.4.1 Antenna system
Pumped storage power station requirements ,entional antennas are used for the large volume areas he station such as the machine hall, the undert s2roa11d 400 kV switching station and the external locas. The radiatini cable is routed to provide opcraLie with minimum attenuation in the eonHL „„„, , :o ■ reas of the power station. Heated antennas are d ,n the rower snation reserwir at the top of the problems during winter. Iu kV. 50 Hz i.solating filters are inserted in the cable connections to the radiating cable/antenna at each fixed station to protect the radio equipo: from damage by a rise of earth potential or , H i d u ,: ed 50 Hz voltage, which could result during a fault on the power station electrical system. The radiating cable has a flame-retardant sheath to fire propagation if fire affects the areas through r.,.th,, ;e Inch the cable is routed.
Combining points (points at which lengths of ra diating cables are connected together in a 'tee' or "through' arrangement), have tee units (power splitters) or through-connectors provided to facilitate the location of cable faults. Loops in the cable at these points provide the spare cable necessary for repair and retermination of the cable. The radiating cable combinin point for the machine hall base station is siloNAn (.)(1 Fig 8.75. The radiating cableiii Ithe undtirgLuuild eluding the 400 kV switching station and 400 kV ,:ab1,2 tunnel) is used both for the operation.s channel and the maintenance ,channel. At each fixed station location, the radiating cable terminates on a duplexer to separate the transmitted and received signals: the transmitted signals are routed to the duplexer via a combiner (which combines the
FR., 8.75 Dinorwig pcmtr station radio sytern — radiating cable combitiniv point 737
Chapte r 8
Telecommunications
of channel 2 sited at the high altitude upper wat er reservoir.
fixed station two-channel transmitter outputs) and the received signals are connected via a combining amplifier to the two fixed station receivers (Fig 8.76). ANTENNA qA D.A r
C
• Radio channel 3 Transmission channel, coverin g the underground 400 kV switching station and 400 kV cable tunnel.
ANTENNA
ABLE
The fixed equipment operates from 110 V AC guaran_ teed supplies (battery backed). A block diagram of the radio system is shown o n Fig 8.77.
I I
7I-IANSMITTER :,DMBINER
-,ANSWTTER
FECENEN
FIXED STATION I
F
14.4.3 Handportable radiotelephones COMBINING AMPLIFIER
Two-channel handportable radiotelephones (handpo r t. ables) are provided for use on the operations and maintenance channels and single-channel handportables for use on the transmission channel only. In accordance with CEGB regulations, the maximum output of th e handportable is 0.5 W effective radiated power (ERP),
TRANSMITTER RECElvER FIXED STATION 2
Flo. 8.76 Dinorwig power station, connection of fixed stations to radiating cables — block diagram
14.4.4 Controllers
The system has four controllers, with channel allocation in accordance with their function, as shown in Table 8.8. Each controller has facilities to:
14.4.2 Radio channels
Three radio channels are used at Dinorwig power station. These are listed below, together with their function and area of cover.
• Monitor the status and alarms of the fixed stations. • Monitor the use of the system by other controllers.
• Radio channel 1 Operations channel (covers underground, external administration building, external lower reservoir area).
• Select and monitor each radio channel. • Control the use of talkthrough for each radio channel monitored (to enable handportables on the same radio channels to speak to one another).
• Radio channel 2 Maintenance channel (cover as channel 1), but with facilities to extend to the upper water reservoir when mobile staff are working or travelling to/from the upper water reservoir. This is to minimise the broadcasting of station radio traffic over a wide external area from the antenna
• Interconnect radio channels. • Broadcast on all radio channels. • By-pass receiver voting control on each radio channel.
TABLE
8.8
Personal radio system controllers — channel allocation
Location Reception desk (Station administration building)
Supervisor's desk (Central control room)
Unit desk (Central control room)
400 kV switching station
/38
Controlled channel I and 2
Areas covered Underground areas
2
Upper water reservoir
3
400 kV switching station station and cable tunnel
I and 2
Underground areas
2
Upper water reservoir
3
400 kV switching station and cable tunnel
3
409 kV switching station and 400 kV cable tunnel
Pumped-storage power station requirements
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CONTROLLER CHANNEL 3 E ■ XED STATION CHANNELS AND 2 ELSE() STATION CHANNEL 3
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CONTROLLER CHANNELS 322.
CONTROLLER CHANNELS ' 3 2 2. UNIT DESK
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CONTROL ROOM
• CONTROLLER FACILITY 417:E. ON AND USE :-IANNEL 2 F.KED STAT I ON A7 liP.EP PESERVCIR
Fio. 8.77 Dinorwig power station radio system — block diagram
• Provide loudspeaker, microphone or, alternatively, handset operation. • Pro ,,ide indications that the fixed station is transmitting and modulating. 14,4.5 Fixed stations l'i\cd
station details are listed in Table 8.9.
Fixed station transmitters 1-6 operate in the quasisynchronous mode (synchronising of transmitter frequencies to prevent generation of audible interference by two signals of the same frequency but different phase) to minimise mutual interference in areas of transmitter overlap. Receiver voting techniques are included in the scheme which routes the best received signal from a trans739
Telecommunications
Chapter 8 TALII E 8.9
Derails of fixed station Fixed itation
No
louatitrul
Channels
Antenna system
Coi. er
...._._
i —-
---
1
L , W■,:i- ,2rotind !r,]r,
,
!■ , 1111i.:r
Ra•lating “ible mfly l ri dcr_., ou rid '4,11[1112 eAtupment house
4
, Uaderrmliwl ruaLhine kiall
.+
Administration building
6
L:pper water resen,air equipment room Underiiround 400 kV S'A itching station
Radiating cable and antennas
1 and 2
2
External roof-mounted antennas
External roof-mounted antennas and radiating cable
3
mining handportable to the controller monitoring the channel. The fixed station receher voting facility will switch from one fixed station receiver to another on receipt of a stronger signal when a transmitting handportable moves from one fixed station receiving area to another. The common equipment cubicle, used by all systems, is located in the underground machine hall and is the local point of the system. All fixed stations and control units have direct circuits, albeit via 50 Hz isolation equipment if necessary, to the common equipment. Most circuits between the common equipment cubic!e, the fixed stations and the controllers, are routed \.ia dedicated short-time fireproof multipair cables hich provide a minimum of 20 minutes security of operation at 1000 ° C in the event of a fire along the cable route. The circuits to the remote fixed station at the location of the upper reservoir, however, are routed via pairs in a CEGB pilot cable between the telecommunications room and the upper water reservoir equipment
room. 14.5 Sound-powered telephone systems I wo separate sound-powered telephone systems are provided at Dinorwig, which will operate if all electricity supplies in the underground plant areas and tunnels are lost. One system is provided for use in the 400 kV cable tunnel and the other primarily for use between the above-ground station gatehouse and the underground areas, should other communication systems fail. The telephones, being dual purpose, are able to work with or without a power supply. Use of a power supply, 740
Underground plant areas and tunnels
I and 2
Radiating cable and antennas
Administration buildinR. lower reservoir and offsite roads
Upper water reservoir and off-site roads
400 kV switching station and 400 kV cable tunnels
however, improves the quality of receked speech. -Ilk calling signal from a telephone is generated by a handcranked generator mounted in the telephone. The received calling signal operates a hooter mounted in the telephone. 14.5.1 System 1 — 400 kV cable tunnel system
This system is provided for operational and maintenance use. A telephone is fitted at each of the 400 kV cable joint bays, the locations at which repair work may be carried out. All of the telephones in the cable tunnel are connected via discrete 25 kV isolation transformers to a common four-pair cable for parallel operation. The four-pair cable is extended to the sound-powered telephone equipment in the 400 kV switching station but electrically isolated from the tunnel by 25 kV isolation transformers. The system equipment in the 400 kV switching station is powered from a 48 V battery supply for security of operation, which is converted to 110 V AC for transmission via the tunnel isolation transformers to all the telephones in the 400 kV cable tunnel, where it is then converted to 24 V AC. However, should the power fail, the system will function in the sound-powered mode. A selector switch on each telephone enables the telephone user to ring either all tunnel telephones and the telephone in the transmission district engineer's office in the 400 kV switching station or the power station CCR. A call initiated from the power station CCR supervisor's desk will call all tunnel telephones and the transmission district engineer's office in the 400 kV switching station.
Construction site telecommunications ------14.5.2 System 2 — power station emergency telephone system ,ency system is provided so that in the event ill's euier tal or partial loss of communication between 3 to N) e-,round areas and the lower works, cornA :.:.Linication may be maintained with the above-ground from sound-powered telephones in the underareas of :he po ■ \. er station. .. .stein comprises a master station at the gate%ith separate circuits to a maximum of 17 ■ rbones (one at the supervisor's desk in the CCR and , : 1, he remainder in the underground works). A cable box is provided at the gatehouse, where all ,ircuits to the underground telephones may be diverted to a local emergency control point should a serious itikleruround emergency occur. This system is similar to that provided for the 400 kV tunnel except that three pairs only are required :o each telephone as only one location, i.e., the 2
atehouse, is to be called.
14.6 Maintenance and commissioning telephone jack system hiN system is provided for point to point speech com. inuniL ation from portable telephones and portable headsets as detailed in Section 10 of this chapter, and 11.o similar circuit patching facilities in a central pa rching cubicle located in the underground plant areas.
14.7 Siren system [ - his system is similar to the siren system detailed in section 11 of this chapter, except that the areas of the rimer station are not zoned for discrete operation of ‘irens in a particular zone. The siren operation is heard in all areas of the station. For this siren system, three unambiguous signals are provided: • station evacuate — continuous sound. • Station alert
wailing sound,
•
short continuous sound followed by a preset silence, then repeated until switched off.
down
I lie system is controlled from the underground CCR and also above ground from the gatehouse. The ,Iiiiehouse siren controller has a facility to monitor the audible operation of the sirens from a microphone in underground transformer hall.
15 Construction site telecommunications 15.1
Initial requirements for British
Telecom services to site ,
.onstruction site could be active for a number of
years and must provide adequate telecommunication services during this period. The telecommunications must satisfy the requirements for CEGB staff, consultants, and contractors. For a 2000 NelW station, the number of personnel on site during the peak of the construction period rises to over 3500. The provision of telecommunications services for a construction site requires adequate consideration well in advance of the arrival on site or the CEGB construction staff and contractors carrying out the preliminary site works. Discussions take place at an early stage with British Telecom ( BT) to advise them of the estimated total public service telephone network (PSTN) requirements and other BT-provided telecommunications services to satisfy the: • Construction site requirements. • Power station requirements. • Grid switching station requirements. These requirements all overlap during the construction period. As many of the new power station sites are in rural areas, BT often have to reinforce their existing networks to provide adequate and reliable access to carry the combined telecommunications traffic generated by the construction site, power station and grid switching station. BT is requested to provide to the construction site a 200-pair of fibre optic cable for initial requirements, plus access to another cable for a small number of circuits, to provide an alternative for emergency circuits should the main 200-pair cable fail. BT is also advised of the segregation requirements for the power station telecommunication circuits in its off-site cable routes.
15.2 On-site telephone cable duct network 15.2.1 General requirements A network of on-site telephone cable ducts is needed to satisfy the constantly changing requirements of the site during the construction period and also the final needs of the power station and grid switching station (if on-site). The on-site cable duct network must be connected to the access points of the off-site segregated BT telephone cable routes serving the site. The on-site network must be designed to continue the physical segregation of duct routes to all permanent power station locations which require segregated routes to the BT off-site telephone network. Good access from the cable duct network is required into the main Construction Site Office, which is the focal point of all telecommunication services for the construction site. The incoming off-site BT telephone cables terminate in the construction site office and telephone cables radiate to distribution points through741
Telecommunications out the site for connection to the dispersed contractors offices and working areas. The on-site requirements for telecommunications services to the contractor's premises is high and to some extent unpredictable. Provision must be made for adequate access to the site telecommunication services, as required, during the construction period. Flexibility to respond to all foreseeable requests during the construction period is important. The provision of ducts throughout the site enables additional multipair and/or fibre optic cables to be routed where required. Some contractor's working areas are re-occupied during the construction period and their needs may be completely different from the previous occupiers. Furthermore, legislation affecting telecommunication services is evolving which sometimes requires alterations to existing telephone cabling. It is not easy to reinforce, or change, telephone cable routes on a construction site which could involve unplanned excavation or (as in the past) the temporary provision of poles and overhead li nes, which are subject to damage by mobile cranes. Underground duct routes of one, two and four 100 mm PVC ducts connecting into heavy duty carriageway boxes are provided. Carriageway boxes with robust removable covers ensure immunity from damage by contractor's loaded vehicles. The provision of strategically placed carriageway boxes and adequate spare duct space ensures flexibility of response to requests for changes to the telephone cable network.
15.3 Telecommunications systems and services The following telecommunications systems and services are required for construction sites: • PABX operated by the CEGB to provide on-site and off-site telephone services for all construction site personnel, i.e., CEGB, consultants and contractors. • Emergency telephone system for reporting accidents, fires, plant emergencies, etc., to the gatehouse and/ or medical centre. • Site emergency warning system. • Pay telephones. • Radio paging system. • Site radio system. • Handportable radiotelephone communications. • Data, telex and facsimile services. 15.3.1 Private automatic branch exchange ( PABX)
It is present CEGB policy to provide a single PABX for all telephone services for a main construction site. The PABX provides all on-site and off-site telephone services for CEGB site staff, contractors and other site organisations. The PABX is located in the Main 742
Chapter 8 Construction Site Office which, as previously stated, i s the focal point for the site telephone cables to contractor's offices and working areas. The PABX belongs to the CEGB and the use of the PABX and the cabling to the contractor's premises is provided by the CEGB as a free site service. 'On-sit e only' telephone calls are also provided as a free sit e service. The contractors pay for the telephone equipment on their premises and also pay for all their outgo_ ing telephone calls to off-site locations, via the PSTN, The extent of use of the PABX telephone services by the contractor and the costs for which the contractor is responsible in respect of their use are detailed in his contract document. The PABX will nowadays be a modern SPC telephone exchange, as described in Section 5 of this chap, ter, having connections to the BT PSTN and the CEGB CTN, and with facilities for connection to the remote main offices of the site major contractors. Routebarring arrangements on the PABX will restrict PABX telephone extensions from gaining access to direct lines to CEGB or contractor's remote locations, if a particular PABX telephone extension user is not permitted by current telecommunications legislation to use them. PABX telephone extensions restricted to on-site telephone calls only will be barred from access to the PSTN, CTN and other off-site telecommunication circuits. 15.3.2 Emergency telephone system
The emergency telephone system (ETS) is entirely separate from the PABX. The ETS telephone exchange is usually located in the construction site main 11 kV substation from which radiates all the 11 kV site supply cables to the dispersed on-site temporary 1 1 kV substations. The telephone cables associated with the ETS also radiate from the 11 kV substation: they are installed and laid in the same trench when the II kV site supply cables are provided to the distributed 11 kV substations. The ETS telephone cables to each distributed 11 kV substation are terminated on a distribution box on the fence of the substation and an ETS telephone is installed on the substation fence wired into the distribution box. ETS telephones required in the working areas of the site are cabled to the nearest ETS distribution box. The ETS common equipment in the main 11 kV substation is powered from a battery supply having a minimum standby capacity of 24 hours. It is CEGB practice to use a PAX for the ETS. ETS telephone extensions located at internal and external working areas are able to dial the security officers in the site gatehouse, or the medical centre, in the event of an emergency. 15.3.3 Site emergency warning system
A purpose built site emergency warning system (EWS) is provided, controlled from the site gatehouse and
Construction site telecommunications telephone pairs in the ETS telephone cable network. The EWSi s required to alert construction site site emergencies which may require action and of oaff also a means of informing on-site personnel of other CEGI3 nuclear power stations have been adjacent to an existing nuclear station whose eillerD.:nev warning system uses sirens. To provide an s for the construction site with unambiguous signals which do not conflict with the siren signals of the nuclear station, a system of ubiquitous elecironic transducers controlled from a control panel in nstruction site gatehouse is provided. co The control equipment is powered from a dedicated asv battery having a 24-hour standby capacity. The ontrol panel mounted in the gatehouse can initiate distinct signals from the electronic sound trans[hra Jucers on the construction site, these are: \ostrecent
• Site evacuate —
continuous audio signals of 0.5 s
required in external locations: most pay telephones are located in site buildings such as the site office reception, gatehouse, site canteen and in the site hostel recreation and sleeping areas. It is essential that a sufficient number of pay telephones are provided in the site hostel to enable contractor's staff to call their families during their meal and leisure time. To minimise possible theft and fraudulent use of the pay telephones the following precautions are taken where possible: • Pay telephones are installed in supervised areas. • Pre-paid card-operated telephones are provided in preference to coin-operated telephones. • Heavy duty cash boxes are provided for coinoperated telephones. • Access to PSTN is restricted to outgoing calls only, to prevent the fraudulent use of transfer charges on incoming calls routed via the PSTN operator.
on and 0.5 s off. three signals of 0.5 s on and 0.5 s off, followed by a pause of 4 s before repeating. Spare signals (use determined by Site Manager) — three signals of 2 s on, 0.5 s off, 0.5 s on, 0.5 s off, 0.5 s on, followed by a pause of 4 s before repeating.
• Fire first aid team —
•
The transducers use pairs in the ETS telephone cabling network. Each transducer may be tested for correct operation from a nearby test pushbutton. The test button is act ated for use during the test at the gatehouse control panel. 15.3.4 Pay telephones lay telephones provide direct access to the PSTN for !dephone calls to off-site locations but they require ad‘ance confirmation that the caller will pay for the call. l'sso types of pay telephones are provided on CEGB i.onstruction sites and associated worker hostel sites, I C., coin-operated and pre-paid card-operated. Insertion of the coin or card enables the call to be initiated and the cost of the call to be recovered from the appropriate number of inserted coins or by magnetic deletion oil the inserted 'phone card' of the appropriate number ol pre-paid call units. Telephone calls to the off-site BT l'SIN telephone operator service and the off-site public emergency services are available without the need to insert coins or a 'phone card', but on-site emergencies %% wild normally be reported to the on-site emergency eo,ices using the ETS, PAX or PABX telephones. Coin and card operated pay telephones are usually prm, ided and installed by BT, and the CEGB provides all necessary on-site facilities. The CEGB is required to provide kiosks, or appropriate accommodation, for pay telephones which are ,
It is necessary for the pay telephones to receive call charge pulses from the off-site BT PSTN telephone network to operate the coin payment and card payment equipment of the pay telephones. At sites having a rise of earth potential problem, the transfer of pulses through the isolation equipment fitted on all working pairs of the incoming BT telephone cable presents problems and special isolation equipment is necessary. Isolation equipment is not necessary on sites being served by incoming fibre optic cable. 15.3.5 Radio paging system
A radio paging system is provided for each construction site using techniques and equipment detailed in Section 7.3 of this chapter. The direct speech facility is not used. The system is completely separate from the power station system. The two systems operate on different frequencies so that there is no mutual interference during the period when both systems are in use. Paging is a particularly useful facility for the site staff, many of whom could be anywhere on the site. The facility provided by the pager alphanumeric display enables the paged person to respond to the call when convenient and allows the paging person to carry on with other work in the meantime. The system should be capable of providing for the needs of all nominated site staff including CEGB, consultants, contractors, etc., who will benefit from its use. Access to the system from the site PABX will enable the paging system to be used from most locations on site and the provision of good coverage of the site by one system only will justify the cost of additional slave transmitters and antennas. In addition to access to the system from the PABX, separate direct access will be available by the site PABX operator who will also have facilities for pro743
Telecommunications viding limited changes to the system, e.g., to enable spare pagers to replace faulty pagers and respond to the same PARX pager code. 15.3.6 Site radio system
Chapter 8 vided to link the on-site computer to one or more of the major CEGB computing centres. The data circuits are either routed via the CEGB corporate data network ( CDN) or via direct circuits rented from BT or MCL. Data terminals at the construction site have access to the local computer and some have direct access to the major CEGB computing centres. Proprietary equipment is used for the data applications. The equipment is usually updated and/or replaced during the construction period to keep pace with current developments. Access to the BT Telex Network and proprietary equipment is provided for sending and receiving telexes. Proprietary facsimile equipment to operate via the CEGB Corporate Telephone Network and the BT PSTN is also used to transmit and receive visual information and documents at remote locations.
A radio system is prw,ided for construction site use and is completely separate from the systems provided , tor the power ;[zliion The system is pro \ ided for use by the site security and medical teams and operates on UHF channels ;elected from the group of frequencies allocated to the Joint Radio Committee of the National Fuel Industries. Fixed stations are provided at the construction site gatehouse or main sire office, and are operated by the security and medical staff, and the telephone operator. The fixed stations provide communication to all external areas of the construction site during the initial site preparation and, if necessary, are extended to indoor areas of the site by the use of one or more fixed stations also controlled from the gatehouse, site office or ambulance room. The fixed stations operate to handportable radio telephones (handportables) carried by the security staff, the medical teams and other nominated staff. Some site ambulance(s) have been equipped with hanciportable holders into which the handportables may be inserted when the medical staff are using the ambulance. This enhances the performance of the handportables and the signal received by the handportable is relayed through a loudspeaker unit in the holder. However, this arrangement has been found to be unreliable due to intermittent failure of the plug/ socket and is no longer recommended. A standard vehicle-mounted radio is nowadays preferred. The radio system uses open channel working so that all handportables are able to monitor the transmissions from the fixed station and consequently be aware of all emergencies. More recent systems use radio trunking techniques and handportable or mobile radios having pushbutton keypads. The equipment and techniques used are detailed in Section 8 of this chapter.
The use of vantages:
15.3.7 Radio telephone handportables
• Wide frequency bandwidth and high data transmission speeds.
Handportables for operation on the single-frequency si mplex channel of 169.050 MHz, as detailed in Section 8.2.4 of this chapter, are provided for local point-topoint communication on the site and for other commissioning purposes. This VHF channel supplements the UHF handportable system for construction site security and commissioning purposes. 15.3.8 Data, telex and facsimile services All major CEGB construction sites have art on-site computer for site management. Data circuits are pro744
16 Future trends and developments
1 6.1 Connections to off-site telecommunication networks Currently, the majority of CEGB power stations rely, for off-site telecommunications, on access to the British Telecom telecommunication network, the connections being made via BT multipair telephone cables to the power station, as described in Section 2 of this chapter. However, the requirements for telecommunication circuits to power stations are increasing dramatically and alternatives to existing practices are being considered, as listed below: • The use of fibre-optic cables to replace or co-exist with telephone cables. • The use of microwave links to replace or co-exist with telephone cables. • Access to telecommunication networks other than the BT network, e.g., MCL networks.
fibre-optic cables has the following ad-
• Using digital signalling techniques many circuits for data, telephony, telemetry, etc., may be carried on each fibre core. • No conduction of the rise of earth potential during faults on the electrical system from the power station to the off-site telecommunication networks. • Reduced space taken in cable ducts. The use of microwave links also enables many circuits to be provided for data, telephony, telemetry, etc. Access to other telecommunications networks from the power station could include the Mercury Corn-
`1111111P0
'
Future trends and developments s Limited (MCL) network, the access to be via microwave or fibre-optic cable. •h could otild be dependent on whether or not MCL „rcrating in the area of the power station and, if her there \% as an economic case for extending t area. The other network to which ric.it,i.% 01k into the he made available would be the CEGB he cables for which are being i
,ullicat on
'•
in the earth wire, or alternatively wrapped ,,..),floritcd the earth %%ire, of the CEGB 400 kV and 275 kV
1,.w,iniion lines. This will eventually provide access
to the network at most of the 400 kV and 275 othstations many' of which are co-sited at, or near,
\.• Kill power stations.
16.2 On-site cabling range of cables for telecommunications is being j ,2 A doeloped which is suitable for use at future nuclear 1,, mer stations. These are cables having a sheath which • duees only a small amount of toxic fumes when it ', ur ns: they also incorporate an insulated single-core ,, r ih %%ire for remote earthing of telecommunications ,Httipment connected to the PABX system, for PABX :.:lephones which use an earth recall facility for transfertelephone calls to other PABX extensions. ,
16.3 Telephone exchanges \, detailed in Section 1 of this chapter, two telephone . . whanges, a PAX and a PABX are at present provided
to ,,crve the needs of CEGB power stations. In addition, here is a separate automatic Private Control Exchange which is provided for Grid System Operations telephony purposes, details of which are included in hapter 12 of this volume. Consideration is being given within the CEGB to reducing the number of telephone exchanges in a power , .][ion from the three mentioned above to either: • No telephone exchanges, i.e., a PABX and PCX. Ihe PAX would combine the presently-provided PAX and PABX, with the PCX providing automatic telephone facilities for system operation telephony needs. • One telephone exchange to serve all automatic tele-
phone needs of a power station and providing PAX, \BX and System Operation telephone requirements. lio[h the above options may only be viable when the ( EGO becomes an 'approved maintainer' by the 'Department of Trade and Industry', so that full main:rt.ance of the telephone exchanges may be carried out. This would enable CEGB staff to exercise control of :h ,! maintenance and to carry out repair work should lie equinment fail, thus minimising the outage time the equipment. Approved maintainer status would " 1 ■ 0 enable work to be carried out by CEGB staff if ti(Itistrial action is being taken by the existing licensed ,
'approved maintainers' (public network contractors and PABX manufacturers). The CEGB as an 'approved maintainer' would thereby be able to provide the service which at present is only permitted on the PAX.
16.4
Radio systems
The radio systems used in power stations, which are described in Section 8 of this chapter, have been de‘eloped since radio speech communication for rco.ing, power station staff was first introduced in the 1960s. However, much of the equipment is now obsolescent and ready for replacement. Also, in 1986, the Department of Trade and Industry advised the Joint Radio Committee of the nationalised fuel and power industries that the 12 UHF channels, which have 25 kHz spacing between adjacent channels allocated for the exclusive use of the industries, were to be changed by 1991 to 24 UHF channels having 12.5 kHz spacing, using the same UHF frequency spectrum. The channels had previously been used almost exclusively by the CEGB but other bodies of the fuel and power industries made known their intention to make use of these additional channels. The CEGB set up a working party to consider their requirements and to report on what action should be taken. They reviewed the existing radio systems operated by the CEGB which generally use dedicated RF channels for particular functions, i.e., operations, maintenance, security, emergency, etc., and also the use of trunked radio, the technology for which has recently become available. Of the systems considered by the working party, the trunked system offered the most effective way of providing the presently perceived needs of the power station user for medium and large stations. It was also considered that small stations would use the same basic radio equipment without the trunking operation, which is not suitable for less than five radio channels. 16.4.1 Trunked radio system
The working party agreed that a multichannel trunked system, using one dedicated channel for signalling/ control and the remaining channels for speech traffic, would be most suitable for large and medium power station use. All user groups would have access to all speech channels, thus optimising total system use. The system would comprise three sub-systems, i.e., antenna system, fixed station/control equipment and radiotelephones, each of which is to be discrete to facilitate alternative provision of supply. Figure 8.78 shows a block diagram of the system. To originate a call, a roving user would switch on his handportable radio telephone and seize the control channel. The control channel would allocate a free speech channel to the mobile user and transmit a code back to the roving user's radiotelephone to switch it to the free speech channel. The roving user would then receive a dial tone. The roving user is then able to 745
Tefecornmunications
Chapter 8
TO ANTENNA SYSTEM oI, NTENINAS AND RADIATING CABLE)
COMBINER
TRANSMITTER RECEIVER SIGNALLING AND CONTRaL CHANNEL
TRANSMITTER RECEIVER
TRANSMITTER RECEIVER
SPEECH CHANNEL
SPEECH CHANNEL
CENTRAL CONTROL UNIT AND PROCESSOR
STATION PAX AND,OR PABX
SPEECH CHANNEL
TIIANSMITTE.
Cr A V IF
MANUAL CONTROLLER ANDOR OPTIONAL DIRECT TELEPHONES
OPTIONAL EXPANSION
RADIO PAX UNIT
TRANSMITTER RECEIVER
HANDPORTARLE SYNTHESISED TRANCEIVER
Fic. 8.78 Trunked radio system — block diagram
key the required control point or direct telephone (connected to the central control unit or radio FAX unit), or key a telephone extension on the power station FAX or PABX. A call for a roving user would be routed via the central processor unit, which will allocate a free speech channel and transmit a code on the control channel to alert the roving user and also to switch the handportable to the allocated traffic channel. The traffic channel
would be held until the originating caller releases the call or, alternatively, the call may be released after a pre-programmed time-out period. It was also agreed that the following applications would apply to all stations: • Plant operation. • Plant maintenance. • Fuel and waste handling. 746
• Station services/safety. • Security. • Fire. • First aid. • Visiting personnel/contractors. In addition, for nuclear stations, there would be a health physics application. The various user requirements are listed below.
Radiotelephones • Keypad. • Pre-programmed single-button call to user's control point. • Abbreviated keying of users contacts simulated dedicated channel.
Additional references override. priorlEY Ordinary keyed digits call (direct extensions or via • FAX or PBX).
•
• •
• Fixed station
Transmitter output with use of ferrite isolators to minimise intermodulation products and to facilitate multiple fixed station/composite antenna systems. Transmitter and receiver combining networks to enable a common antenna/radiating cable system to be used.
Conference calls 'station emergency group calls. requirements: isual indication/vibrator oi n-1 bleep H Bleep loudness independent of volume control ( preferably from separate audible call
Transmitter, receiver and control equipment to
l
transducer 1,$)
(i.1)
Drop-ISC withstand capability
Single-channel/multichannel working/automatic control of RF channel
(e) Noise cancelling/desensitised microphone n H ea dset with pushbutton or voice-operated
transmitter (.0 Methods of carrying handportable unit: top pocket overall/shoulder harness/belt harness.
be approved by British Approvals Board for Telecommunications (BABT) to permit connection to the PABX. Antennas and radiating cable to provide maximum coverage of station and site areas.
• Antenna system
The basic operational requirements of the preferred system
• Station coverage by all channels. • Simplicity of operation (single digit operation for group control desk). • Non-blocking for priority/emergency users. • Extension of station PAX.
ihrect telephone control points
• Ordinary keyed digits call to handportable. • Priority override keyed digits call to handportable. • Conference/station emergency group(s) calls (open channel). s• wiron PA X and/or PA BX access
• Direct dialling between PAX/PABX telephones and handportable radiotelepliones/vehicle-mounted radios. S. v%tem and equipment detail • Frequencies used
The channels to be used by a
'stem will be allocated by the JRC from the band
a 24 UHF channels available to them. This is done after consideration of the need (a) to minimise interference to other users of the channels within he mutual reception range of the power station radio system and (b) to minimise the on-site intermodulation products.
A pilot scheme of the above system is being engineered for use at Ironbridge power station (1988), to determine the performance and acceptability of the system for power station use.
17 Additional references Philips Telecommunications Ltd Engineering Notes: TSP 1267
Minimising Intermodulation and Blocking Effects in VHF/UHF Radiotelephone Systems.
TSP 377
The Location of Antennas on Motor Vehicles
TSP 427
Electrical Noise in Motor Vehicles
TSP 480/1 Intermodulation in VHF and UHF Radio Systems — locating and minimising the effects TSP 588/1 The use of Circulators/Isolators to Minimise Transmitter Intermodulation I TT
Reference Data for Radio Engineers (Sixth Edition)
MPT
Performance Specifications issued by the Radiocommunications Agency of the Department of Trade and Industry
Morton, A. H.: Advanced Electrical Engineering: Pitman: 1966 Electronic Engineers Reference Handbook (fifth edition): Edited by Mazda, F.: Butterworths
747
CHAPTER 9
Emergency supply equipment 1 introduction 1.1 Introductory statement on batteries 1.2 Introductory statement on systems 2 Batteries 2.1 Explanation of terms 2.2 Possible types 2.2.1 Heavy duty lead-acid Plante positive plate cells 2.2.2 Tubular plate lead-acid cells 2.2.3 Pasted flat plate lead-acid cells 2.2.4 Nickel-cadmium cells 2.2.5 Sealed lead-acid SLA) or recombination cells 2.2.6 Summary 2.3 Heavy duty lead-acid Plante cell — description and chemistry 2.3.1 General 2.3.2 Positive plates 2.3.3 Negative plates 2.3.4 Separators 2.3.5 Plate interconnections or group bars 2.3.6 Plastic containers 2.3.7 Cell lids 2.3.8 Vent plugs 2.3.9 Terminal pillars 2.3.10 Terminal pillar seals 2.3.11 Intercell connectors 2.3.12 Polarity identification 2.3.13 Electrolyte 2.3.14 Battery stands 2.3.15 Chemistry 2.4 Battery accommodation 2.4.1 General requirements 2.4.2 Ambient temperature 2.4.3 Ventilation 2.4.4 Lighting 2.4.5 Battery main connections in battery rooms 2.4.6 Access to battery rooms 2.5 Initial tests, charging, maintenance and site testing 2.5.1 Tests in manufacturer's works 2.5.2 Tests at site 2.5.3 Charging 2.5.4 Factors affecting cell life and precautions to be taken 2.5.5 Inspection 2.5.6 CEGB experience 2.5.7 The case for testing 2.5.8 End of life 2,5.9 Uncharacteristic behaviour of odd cells 2.5.10 System tests of essential battery-backed DC systems 3 Battery systems 3.1 Introduction 3.2 Provision of DC systems 3.2.1 220 V DC systems for switchgear closing 3.2.2 110 V DC systems for switchgear control, protection and interlocks 3.2.3 48 V DC systems for telecommunications, plant control and alarms 3.2.4 250 V DC systems for emergency lighting and emergency drives
748
3.3 Duplication of battery/charger systems 3.4 DC system voltage limits 4 Chargers 4.1 Introduction 4.2 Required characteristics 4.2.1 Initial charge 4.2.2 Maintaining charge 4.2,3 Charger ratings 4.2.4 Boost charging 4.2.5 General additional requirements 4.2.6 Earthing 4.2.7 Protection and monitoring 4.2.8 Alarms 4.2.9 Nuclear safety 4.3 Description of equipment 4.3.1 Introduction 4.3.2 Basic principles 4.3.3 Main transformer 4.3:4 Thyristor rectifier 4.3.5 Control board 4.3.6 Reference transformer 4.3.7 DC transformers 4.3.8 Display 4.3.9 Battery float/boost control circuitry 4.4 Testing 4.4.1 Introduction 4.4.2 Type testing in manufacturer's works 4.4.3 Routine tests in manufacturer's works 4.4.4 Tests at site 5 Diesel generators 5.1 System requirements 5.1.1 Purpose of diesel generator installation 5.1.2 Starting and loading 5.1.3 Rating and number of diesel generators 5.1.4 Protection against external hazards 5.2 Engine and auxiliaries 5.2.1 Engine types and characteristics 5.2.2 Engine design and construction 5.2.3 Starting equipment 5.2.4 Cooling system 5.2.5 Fuel oil systems 5.2.6 Inlet and exhaust air pipework, turbochargers and silencers 5.2.7 Governors 5.3 Generator and electrical equipment 5.3.1 Generator design and construction 5.3.2 Excitation equipment and automatic voltage regulator ( AVR) 5.3.3 Diesel generator control and protection equipment 5.3.4 Control of auxiliary systems 5.4 Testing 5.4.1 Tests in manufacturer's works 5.4.2 Tests at site 5,4.3 In-service operational testing 6 Additional references 6.1 British Standards (BSI
Batteries 1 Introduction electrical industry developed rapidly at the start he t%Sentieth century, the advantages of high voltage ; le and distribution meant that the original DC radually replaced. This change from DC Hops e 0 ppiv introduced many new problems associated ,u % olt ages used. Eli the high control of s%%itehes and equipment was inj[C ed and, because of their reliability and flexibility, j u ,: ies were considered to be the best source of supL..,, :cr )erating circuit-breakers and the many safety , t or . j protective devices which are part of the complexity 'w 4 AC aeneration and distribution. In the 19405 central control rooms replaced local boder and turbine gauge boards in power stations. rhere Was then a need for electrical transmission of ,„ ur ed quantities, e.g., temperature, pressure, etc., ;rout plant to the central control room. Electrical control began to replace the older pneumatic r e mote Ind hydraulic systems. These requirements demanded er larger batteries and their associated chargers to pro% ide standby supplies for the control and operation f p l an t, varying from three hours to six hours dura:Lon. in the event of a complete loss of Grid supplies. Shortly afterwards, studies suggested that dependnee on batteries could be reduced to half-hour duration, after which time diesel generators or gas-turbine ,tenerators could take over the emergency load until Grid supplies were restored. This reduced battery sizes bird proved to be an economic solution; it is now .,:enerally adopted by the CEGB, with a preference for Wesel generators because of their superior starting rehability and capability of picking up load very rapidly. Ihis arrangement ensures safe shutdown of plant, particularly nuclear reactors, and facilitates a rapid rN.art on restoration of Grid supplies, as the diesel L%.acrators are able to recharge the batteries in readiness or this event. Modern power stations and substations employ a laintber of batteries and chargers of different sizes And voltages for a variety of duties. Nuclear power , ituions require larger batteries and chargers than con%Littional stations for essential duties, due to nuclear , alety requirements. In earlier years, batteries and chargers were provided 011 a station basis. However, because of the ever increas:Ng demands on batteries and the physical growth of He power stations, it was found to be more economic Or provide batteries for each boiler/turbine unit. Almough this increased the number of batteries in a Power station, the extra cost was compensated by the reduction in cable sizes which, because of the long distances involved in the station battery arrangement, Acre sized on volt-drop rather than carrying capacity. For nuclear reactors operating on a quadrant (i.e., tour train basis) for safety reasons, batteries, chargers and diesel generators are sub-divided further to make each quadrant of the reactor completely independent. rhis ensures that a fault on one quadrant does not
1
jeopardise the satisfactory operation of the remaining quadrants. 1.1 Introductory statement on batteries The batteries installed in modern CEGB power stations are almost exclusively of the lead-acid high pet formance Plante positive-plate type, individually enclosed in transparent cell boxes, with positive and negative plates immersed in dilute sulphuric acid (see Section 2.3 of this chapter for details). They have given satisfactory service, with a life of around 25 years, depending on usage and maintenance. In the past, other types of batteries have been investigated, such as tubular positive-plate lead-acid cells, pasted flat plate lead-acid cells and nickel-cadmium cells, but have been rejected on a basis of lifetime costs. Maintenance-free (sealed) batteries have come on the market in recent years, but are not at present considered suitable to replace the heavy duty lead-acid battery in power stations because of their low life expectancy and lack of service experience. A short description of the above alternatives to high performance Plante cells is given in Section 2.2 of this chapter. 1.2 Introductory statement on systems Modern power stations require a number of different DC supplies for telecommunications (48 V), control and instrumentation (48 V and 110 V), switchgear closing (220 V) and tripping (110 V), emergency lighting and emergency motor drives (250 V); for details see Chapter I. These supplies are derived from combinations of batteries, chargers and DC switchboards. in a large nuclear power station with two advanced gas-cooled reactors and two 660 MW turbine-generators, there are between 70 and 80 batteries and their associated chargers. More details of these systems are given in Section 3 of this chapter. Under normal (mains healthy) conditions, each battery and set of load circuits floats across its associated mains fed charger. The charger provides a constant output voltage and at this controlled voltage supplies the whole of the continuous load and automatically maintains the battery in a fully charged condition. Under emergency (mains or charger failure) conditions, each battery supplies the whole of its system load for a specified maximum period, thus each battery provides an automatic no-break, back-up supply for its charger at all times. The normal open-circuit voltage of a fully charged cell, with a specific gravity of 1.207 at 20 ° C, is 2.03 V.
2 Batteries 2.1 Explanation of terms
Capacity The quantity of electricity, usually expressed in ampere-hours (Ah), that may be taken from a cell 749
11P Emergency supply equipment at a particular discharge rate under specified conditions of voltage and temperature. Discharge rate The capacity of lead-acid Plante cells is greatest at low discharge rates and lowest at high rates of discharge. The discharge rate is defined as the steady current in amperes (A) that can be taken from a battery of defined capacity (Ah) over a defined period (h). Batteries for CEGB power stations are normally specified for a 10-hour rate. Voltage The capacity can be related to any practical limit of cell voltage and the higher the final voltage at minimum discharge, the lower will be the capacity of the battery. The final voltage to which the battery will supply the duty is defined in terms of volts per cell. Temperature Low battery temperatures temporarily reduce the available ampere-hour capacity and discharge voltage. Capacity and voltage are restored to nominal with a return to normal temperature, even without a charge. An increase in battery temperature results in an increase in capacity, particularly at high rates of discharge. The capacity of lead-acid Plante cells is specified at 20 ° C. Rating The ampere-hour capacity of a positive plate or cell assigned to it by the manufacturer, under specified conditions of discharge. Charging The passing of an electric current through a cell to bring it to a chemical condition where it is capable of supplying electricity to an external circuit. The quantity of electricity put in is known as the 'charge' and is usually measured in ampere-hours. Fully charged The condition of a battery when the voltage and the electrolyte specific gravity of every cell have not varied appreciably during three consecutive hours at the end of the charging period, account being taken of temperature variations. Discharge The quantity of electricity in Ah taken out of a cell connected to an external circuit when the current flows through the cell in the reverse direction to that of charge. Plate The unit that, singly or in groups, is submerged in electrolyte of dilute sulphuric acid, or potassium hydroxide in the case of nickel cadmium cells (see Section 2.2.4 of this chapter), so that it forms the whole or part of one of the electrodes of the cell. Positive plate The plate that forms the anode or part of the anode during the charge. For lead-acid batteries, it can be of three main types: Plante, tubu750
Chapter 9 lar or flat plate. Negative plate The plate that forms the cathode o r part of the cathode during the charge. Plate group A complete electrode consisting of either positive or negative plates, together with a group b ar and a terminal pillar. Separator An insulating structure used plates of opposite polarity.
CO
separate
Container A box of suitable material, usually plastic in CEGB power stations, in which the plate groups and separators are assembled.
2.2 Possible types 2.2.1 Heavy duty lead-acid Plante positive plate cells
This cell is derived from the conventional long-life lead-acid battery and is designed to provide low to medium currents for, say, 1-3 hours. It has a high cell voltage and is tolerant of temperature changes, although these affect its output capacity. With good maintenance, a life of 25 years is not uncommon in CEGB experience. Plante positive plates are made of pure lead instead of the pasted-plate of a flat plate battery (Fig 91 (a)). An electrochemical formation process produces a thin layer of lead dioxide on the total active surface area. The enclosures are generally transparent styrene acrylonitrile (SAN), stress-relieved to give clarity and mechanical stability through life, together with 'at a glance' inspection of electrolyte levels. The SAN enclosures replace the moulded-glass containers and leadlined wood containers used previously. The latter were employed for very large capacity cells. One major advantage of this type of cell is that maintenance personnel can assess life by visual inspection (see Section 2.3 of this chapter for a detailed description of the high performance Plante cell). 2.2.2 Tubular plate lead-acid cells
They are physically some 66 07o of the volume and 80% of the price of the corresponding ampere-hour capacity Plante positive plate battery, but the life expectancy of tubular positive plate batteries is only 10 to 15 years. This was confirmed by experience at Heysham / and Hartlepool nuclear power stations, where tubular plate lead-acid cells needed replacement after about ten years. They have higher open-circuit losses and need more frequent inspection. Tubular plates (Fig 9.1 (b)) are constructed from tubing manufactured from Terylene or a combina tion of perforated PVC and woven glass fibre, fitted
Batteries
(b) Tubular plate construction {lead-acid) al Plante plate construction (lead-acid)
(d) Pocket plate
construction (nickel cadmium)
(c) Flat pasted-plate construction (lead-acid)
FIG. 9.1 Typical construction of battery positive plates
ov er cast antimonial-lead spines. The tubes are filled ith lead oxide and then undergo a formation process. Their construction does not permit a visual inspection of the plates: their condition is therefore not easily ascertainable and any slow deterioration is not readily detected. Again, the enclosures are generally SAN, stress-relieved to give clarity and mechanical stability throughout life, together with 'at a glance' inspection of electrolyte levels. 2.2.3 Pasted flat plate lead acid cells -
These suffer from the same disadvantages of life ex-
pectancy and open-circuit losses as tubular positive plate lead-acid cells. Their life expectancy is even lower, about 5-6 years. They are designed for low performance applications only and are unsuitable for even moderate discharges lasting more than a few minutes. The flat plates consist of a paste made from lead oxide, sulphuric acid, water, and other additives, applied to a lattice grid made of lead or lead alloy. The plates are dried under controlled conditions and then undergo a formation process (Fig 9.1 (c)). Again, the enclosures are generally stress-relieved SAN. 751
Emergency supply equipment
Chapter 9
2.2.4 Nickel-cadmium cells
2.2.5 Sealed lead-acid (SLA) or recombination cells
When correctly maintained, nickel-cadmium cells can have a life of more than 30 years, during which approximately 10-20% capacity is lost. They employ perforated steel pocket plate construction, using nickel hydroxide as the basis of the active material for the positive electrode and cadmium hydroxide for the riegati% e electrode (Fig 9• I (d)). The electrolyte is an aqueous solution of potassium hydroxide, with the addition of lithium hydroxide. The purpose of the electrolyte is solely to support the ieactions between the electrodes and there is no significant change in specific gravity from a fully charged to a discharged condition. The containers can be of nickel-plated steel, thus affording maximum strength and durability for use in rugged environments, also where shock and vibration are present, Alternatively, the containers can be of translucent high-impact polystyrene plastic for ease of maintainance and mechanical strength and stability throughout an extended life. These also enable the electrolyte level to be checked at a glance. An advantage of the nickel-cadmium battery is its ability to be left idle for long periods in any state of charge and its rapid recovery after neglect by toppingup and recharging. The following disadvantages outweigh the advantages: • It is not possible to check the state of charge without carrying out a discharge test. • The electrolyte in the cells requires replacement, initially after two years and subsequently between five and eight years. Failure to replace reduces the high rate discharge capacity significantly. • The internal resistance is higher than for a lead-acid cell, hence there is a greater propensity to higher electrical noise levels generated by currents such as charger harmonics, signals, telephone speech, etc. These currents generate volt-drops across the battery internal resistance and are transferred to other circuits connected to the battery. • The cost of a nickel-cadmium battery is higher than the corresponding lead-acid Plante battery as a larger number of cells is needed for the same ampere-hour capacity because of their lower cell voltage. Maintenance costs of a nickel-cadmium battery are higher than for a lead-acid Plante battery because of the larger .number of cells and the greater need for cleanliness to prevent tracking between poles due to close spacing. Its high rate performance is lower than that of a lead-acid Plante cell. Any attempt to boost charge may result in the 'self destruct syndrome'. These cells have been known to disintegrate somewhat forcefully and resoundingly after such a treatment, due to the release of large volumes of hydrogen and oxygen. 752
When a traditional lead-acid battery is charged normally, the electrochemical reaction evolves unpleasant and potentially explosive hydrogen and loss of water occurs (for details see Section 2.3,15 of this chapter). Hence the need for ventilation and topping-up. By th e use of 'gas recombination' both these problems lia\,e been solved, whilst retaining the inherent advantages of low cost and long life of the lead-acid battery. The gases usually liberated into the atmosphere during float/recharge operation in conventional lead-acid cells, recombine to form water in a recombination cell. As a consequence, these cells do not lose water during normal operation and therefore topping-up and ventilation are not required. The recombination principle works when oxyge n evolved from the positive plates diffuses through the highly porous glass-microfibre separator to the reactive negative plate and is electrochemically reduced to water. The separator acts like a sponge and holds captive a closely controlled quantity of acid in a stable condition, whilst providing the medium by which as recombination can take place. Even if the cell container is accidentally damaged, it will not leak acid, unlike a conventional lead-acid cell with its copious quantities of dilute sulphuric acid electrolyte. Although the cell is virtually sealed, a safety valve together with a flame retardant device is provided to stop damage by inadvertent overcharging. Hence the term 'sealed' battery is really a misnomer. These cells suffer rapidly from anything other than very carefully controlled voltages. Even under these conditions, their life is claimed to be only ten years and can be as low as three to four years if charging voltage or ambient temperature is increased. Sealed lead-acid cells use a flat pasted construction for both positive and negative plates. A grid alloy with a high hydrogen overpotential is essential to long term operation and lead-tin-calcium alloys are used. The separator is crucial in achieving efficient oxygen recombination in SLA cells. Glass microfibre paper is used for the separator because of its inertness and large uniformly porous volume, so that when the separator is not fully saturated there is an electrolytefree path between positive and negative plates along which oxygen diffuses from positive to negative and there reduced to water. The cells are formed by compressing together the plates and separator into the container with a carefully measured quantity of electrolyte, the lid then being sealed. The containers are of flame-retardant ABS plastic which is mechanically robust and abuse-resistant. It withstands stress, thermal shock and vibration. Like nickel-cadmium cells, the maintenance of recombination cells is essentially limited to monitoring battery and cell voltages and charging current, in
Batteries addition to normal good housekeeping such as cleanliness and tight joints. In addition to being maintenence-free, SLA recombination cells do not require separate ventilated accommodation. Their low internal resistance gives them high ,hort-term current capability for duties such as engine ...,arting. They are also inherently more robust, smaller J lighter than Plante cells for a given duty. an The main advantage they offer is one of civil cost which balance their shorter life and consequently increased lifetime replacement costs. The condition of a SLA cannot be assessed visually and neither can the electrolyte specific gravity be checkIn view of present CEGB maintenance practice, 0:i, ;hese are serious disadvantages. Alternative condition onitoring techniques are being developed by users of m sLA cells; one of these is the comparison of current in parallel strings of cells, a configuration common in SLA batteries. Variations in the string currents i n di c ate problems in one string. Routine discharge testing is also available and special test load sets have b e en developed. Monitors using ripple or pulsed load techniques are other options that are also becoming available. Finally of course, the CEGB practice of p er iodic cell dismantling can be used to assess the residual life of a battery. 2,2.6 Summary The evidence over many decades of satisfactory performance and long life of heavy duty lead-acid Plante cells has led the CEGB to continue their use to the present time. Although the recombination version of the lead-acid cell now appears to offer an alternative which may well be explored in future power station schemes. Initially, lack of operating experience discouraged detailed consideration of its use but there is now a growing %.olurne of such experience. Within the CEGB, Transmission Division have some four years' experience of [hese batteries for telecommunications systems. The use of batteries as emergency power supplies means that condition monitoring is an important issue. While this is a problem with a sealed cell, techniques are being developed and generally experience of failure rates with SLA batteries has been good. It seems likely, therefore, that in the future, leadacid batteries of the recombination type will offer a serious alternative to the Plante cell. Using heavy duty Plante cells and by careful maintenance, only one complete battery replacement may be necessary in the life of a power station, whereas other types necessitate more than one. This considerably increases the lifetime costs for the station, and there are therefore no overall economic advantages in using types other than Plante.
2.3 Heavy duty lead-acid Plante cell — description and chemistry In view of the almost exclusive use in CEGB power
stations of the lead-acid high performance Plante positive plate battery, further details of the cell construction and operation are given in this section (Fig 9.2). 2.3.1 General
High performance Plante cells designed to BS440, now superseded by BS6290, provide the highest integrity source of standby power with a long and predictable life. They are designed for operation under constantpotential float or trickle charge conditions, not involving regular deep cycles of charge and discharge. In addition, their high rate performance makes them particularly suitable for circuit-breaker tripping and closing duties together with diesel and gas turbine starting operations. By virtue of the high power/weight ratio and sealed construction, high performance Plante cells are ideal for installations where space is limited. As mentioned already, they have a typical life of 20-25 years. 2.3.2 Positive plates
The positive plates are cast from pure lead and consist of numerous thin vertical laminations, strengthened by a series of horizontal cross-ribs to increase the surface area by as much as 12 times that of a plain lead plate of similar width and length. This ensures that there is no fall-off in capacity throughout their long life. The positive plates are hung from ledges moulded in the container. 2.3.3 Negative plates
The negative plates are of interlocking design to ensure active material retention and provide balance with the positive plate to give maximum performance and life. The negative group always has one more plate than its matching positive group, so that when the groups are interleaved, each positive plate is located between two negative plates to ensure that both surfaces are worked equally and thus prevent distortion or buckling. The negative plates are supported on ribs in the bottom of the container. 2.3.4 Separators
Separators are made of microporous PVC, providing a complete diaphragm between the plates and giving maximum electrolyte utilisation, together with high mechanical and electrical strength. Separators are chemically inert and their high porosity ensures minimum internal resistance. This permits more efficient circulation of electrolyte and, combined with maximum physical strength, prevents internal short-circuits by active material deposition. 2.3.5 Plate interconnections or group bars
To obtain the desired ampere-hour capacity, each respective group of positive and negative plates are joined 753
Emergency supply equipment
VENT PLUGS
CELL LID --
CELL PILLAR AND CONNECTOR
NEGATIVE PLATE
SEPARATOR
PLANTE POSITIVE PLATE
PLASTIC CONTAINER
FIG. 9.2 • General arrangement of a typical heavy duty - lead-acid Plante cell 754
Chapt er 9
Batteries by group bars made of lead which, dependent h er he manufacturer, may contain a small percentage on t of antimony. Cells utilise fully-welded group bars on ‘ positive and negative groups, ensuring that plate i„; are firmly burned into the group bar. wet
2.3.6 Plastic containers ontainers are injection moulded from trans1 .1 „,tic c raretit stv retie acn,ionitrile (SAN) and stress-relieved, 'a rtg improved transparency and mechanical stability rou,hotit life. The very high insulating qualities minate the need for separate cell insulators. The eli Hilproved transparency enables the electrolyte level and ...ell condition to be seen at a glance. The maximum and minimum levels are marked on the sides of the cell necessary to facilitate maintenance. All containers are much deeper than the length of e plate they accommodate, to allow ample gassing r il Tace above the plates and space below them for the Jownward expansion of the positive plates and the huilci-up of sediment ('mud space'). springs or buffers are provided to hold the plate 2ttoups in position throughout the life of the cell. 2.3.7 Cell lids Cell lids are moulded in an easily-cleaned form from opaque SAN material and are bonded to the container to prevent leakage of gas or electrolyte. They are arranged to carry vent plugs and terminal pillars. During the mid-1970s, because of unsightly appearance, two major manufacturers decided to depart from the, until then, otherwise satisfactory method of bonding the lid to the cell. The new method, using ,ohrent-based cement, appeared to be satisfactory in he short term; in the long term, the joint seal failed and electrolyte started to leak from the cells. Alter some considerable development work, a new method of lid-to-case sealing evolved, using a hot-melt adhesive. This can be used either on the factory .t , )ernbly line or on site to avoid having to return cells to the factory. At present (1988), one manufacturer is iill experiencing difficulties and is carrying out further rescarch.
2.3.8 Vent plugs \,. nt plugs are of special design which effectively returns all acid spray to the cell, but allows free exit of :lie oxygen and hydrogen which are generated towards he end of boost charging. Two polystyrene filling plugs are also fitted to each lid. 2,3
.9 Terminal pillars
For normal usage, terminal pillars are of antimonial lead, giving high conductivity, corrosion-free properlics. For extra high current duties, these pillars are Provided with tinned copper inserts. Dependent on the m anufacturer, cells up to approximately 600 Ah have
a single pillar per pole. Above that capacity, up to about 1400 Ah, twin pillars per pole are used. For the largest sizes, three (and sometimes even four) pillars per pole are provided. Over a period in the late 1970s, one manufacturer reduced the amount of antimony in the pillars. After some years in operation, corrosion appeared on the positive pillar which burst the pillar seals and in some instances even cracked the lids, leading to acid leakage. When this was discovered, a programme of replacing faulty cells was instituted, using pillars with their former proportion of antimony in the composition of the alloy. This meant having replacement cells available to substitute for faulty cells, which could only be reconditioned in the factory. All new batteries supplied since that date have, of course, reverted to the original proportions of antimony and lead in the pillars.
2.3.10 Terminal pillar seals Terminal pillar seals effectively prevent the escape of electrolyte or gas at all times during the working life of the cell under normal usage to prevent corrosion of the pillar above the lid. All cells are pressure tested prior to despatch, to check the integrity of the seals.
2.111 Intercell connectors Similar to the terminal pillars, single, t win and triple intercell connectors are provided depending on the cell capacity. These are usually of lead-plated high con-
ductivity copper, combining corrosion resistance and minimum resistance/maximum current flow. For corrosion reasons, bolt sets provided with each cell are heavily cadmium plated. Intercell connectors for the seismically-qualified batteries used in nuclear power stations are made in flexible insulated braid, instead of solid connections. 2.3.12 Polarity identification A + (plus) sign is moulded into the lid in a minimum of two positions adjacent to the positive pillar, which is also identified by a red terminal ring (dependent on the manufacturer); negative pillars are similarly identified with a blue ring and at the option of the manufacturer with a ( minus) sign moulded into the lid. —
2.3.13 Electrolyte The cells are provided with pure sulphuric acid having
a specific gravity of 1.207 at 20 ° C when fully charged and with the electrolyte at maximum level. For despatch from works, they can be filled with acid and fully charged ready for immediate service after a short refresher charge or, as sometimes used for overseas
destinations and the larger cells for UK service, they are shipped assembled but unfilled and uncharged. 755
Emergency supply equipment
Chapter 9 AEN.
2.3.14 Battery stands Battery stands can be constructed of high quality knotfree timber and finished with three coats of acidresisting paint. Alternatively, steel stands with an acidresistant epoxy coating can be provided. Each stand module is fitted with adjustable nylon feet to allow for any variation in floor finish and for insulation. Batteries can be arranged in single tier or double tier, with single rows for positioning against walls or twin rows where access can be provided from both sides. Where seismically-qualified batteries are provided for nuclear power stations, they are accommodated on special seismic stands using mild steel. They are constructed in a similar manner to the normal stand but use larger cross-section material and additional tie bars. Each module is bolted to the floor. 2.3.15 Chemistry The fundamental parts of the lead-acid Plante cell are two dissimilar plates or electrodes immersed in an electrolyte, i.e., positive plate (lead dioxide), negative plate (spongy lead) and dilute sulphuric acid electrolyte. Cell on discharge
Assuming the cell is fully charged, the sulphate ions from the electrolyte move to the negative plate and give up their negative charge when an external load is connected across the cell terminals. This produces an excess of negative charge at the plate, which is relieved by a flow of electrons via the load to the positive terminal, i.e., from low potential to higher potential, which is opposite to the conventional direction of electric current. This passage of surplus electrons allows more sulphate ions to combine with the lead in the negative plate to form lead sulphate. At the positive plate, the highly oxidised lead dioxide is short of negative charge, so it readily accepts the electrons from the negative plate via the load. Hydrogen ions from the electrolyte now combine with oxygen ions from the plate to form water. This leaves some lead-free to combine with the sulphuric acid to form lead sulphate and more water. As the discharge proceeds and current continues to flow, more lead sulphate is formed in both plates by combination of the acid from the electrolyte. Water is also produced, which helps to dilute the electrolyte, and it is this progressive weakening of the electrolyte by formation of water which provides a convenient way of measuring the amount of discharge taking place. The cell is discharged when its voltage falls rapidly: at this stage, most of the active material has been converted to lead sulphate and the plates are almost identical in chemical composition. Cell on charge
To reverse the chemical changes which take place in the cell during discharge, it is necessary to pass a DC 756
current into the cell in the opposite direction to that of discharge. The charging source must therefore have a voltag e greater than that of the cell or battery to be charged. The charging source connected across the cell supplies an excess of negatively charged electrons to the negatRe plate and creates a shortage at the positive plate. Th e result is that positively charged hydrogen ions are attracted to the negative plate, where the hydrogen combines with lead sulphate to form lead and acid. The shortage of charge produced at the positive plate results in sulphate ions being attracted and combining with the hydrogen of the water to form sulphuric acid. This releases the oxygen ions in the water, some of which combine with the lead of the positive plate to form lead oxide. At the negative plate, the process of recombination of the hydrogen and sulphate continues as long as there is sulphate present. When the process of conversion of lead sulphate to lead is almost complete, hydrogen bubbles form at the negative plate and rise through the electrolyte. This is known as 'gassing'. Similarly, sulphate ions react with water at the positive plate, forming sulphuric acid and leaving oxygen to react with lead to form lead dioxide. When most of the lead is converted, the oxygen appears as gas at the positive plate. The formation of hydrogen and oxygen gas at the plates is a sign that the cell is reaching the
fully charged condition. As the charge proceeds, acid which is released from the plates passes into the electrolyte and the specific gravity slowly increases. Measurement of the specific gravity of the electrolyte during the course of a charge does not give a true indication of the charged condition of the cell or battery. It is not until gassing commences that the stronger acid, liberated from the plates, is mixed with the weaker acid at the top of the cell. Specific gravity readings can therefore be of value only towards the end of the charge, when constancy of readings indicates that all strong acid has been liberated from the plates and the cell is fully charged. Although some gassing is necessary to bring into circulation the strong acid released during the charge, excessive and prolonged gassing can in time shorten the life of a battery by scouring the active materials at the surface of the plates. Hydrolysis of the electrolyte results in loss of water which must be replaced by adding more pure water from time to time. The demands of a battery as regards the amount of topping-up water required, when working at known duty are a good guide to correct charging. Excessive water consumption usually means overcharging, whilst too little means undercharging. The chemical reaction can be expressed as follows: Charged
Discharged PIDSO4
Lead sulphate
PbSO4 +
Lead sulphate
Positive Negative
2H20 Diluted electrolyte
4
-* Pb02 + Pb + 21-12 SO4 Lead dioxide
Lead
Positive Negative
Sulphuric acid
Batteries The arrows are used instead of an 'equals' sign to that the reaction is reversible. ifi Wcate [I will be appreciated that the normal working of ; produces lead sulphate at both positive and 3 barer nc,,,Itive plates, which are reconverted to their original co-ndition by charging. 'Sulphated' is the term usually plied to a battery which has been abused by under. .„[ Fl a or left in a discharged condition for long 1x periods, when the plates become excessively sulphated, l os e porosity and develop a high resistance. In this bnorrnal condition, the sulphated plates will not usu,i ally accept a charge, The important feature of the lead-acid Plante cell [ s he pure lead of the positive plate. The use of this plate ensures that any active material shed during the working routine is reformed on the plate surface by the regeneration of the base lead. During the life of he cell, lead dioxide is gradually lost from the plate laminations forming sediment in the container and is made good by conversion of the underlying surface to lead dioxide during the normal charging and discharg!r w of the cell. This ensures that full cell capacity is always available through its life.
2.4 Battery accommodation Batteries mounted on stands as described in Section 1 .3.14 of this chapter, are normally accommodated in rooms specifically designed for this purpose and for their exclusive use. Figure 9.3 shows a typical arrangement. 2.4.1 General requirements • Battery rooms are well ventilated and dry, with wall and ceiling finishes durable and free from flaking and corrosion. They are generally treated with an acid-resistant paint. This also applies to any metalwork within the
room. Floor finishes are generally antistatic. They are laid level beneath batteries and access areas. Elsewhere they slope to a drain constructed of acid-resistant materials and/or have a retaining sill across internal door sills. The battery room can conveniently house all the maintenance equipment, protective clothing and services. A water tap and porcelain sink is provided in each battery room.
lead to greater evaporation of water from the electrolyte and a significant reduction in service life. 2.4.3 Ventilation Adequate ventilation is provided in all battery rooms to keep the concentration of hydrogen gas in the room within safe limits. It must be remembered that hydrogen is lighter than air and diffuses upwards very rapidly. Because of the potential unreliability of forced ventilation, battery accommodation is designed, wherever possible, for natural ventilation. Although hydrogen and oxygen will diffuse into the air within the battery room, it should be borne in mind that the hydrogen forms an explosive mixture with air when the hydrogen concentration by volume exceeds about 43/4. The aim of the ventilation system is therefore to maintain the average concentration below 1 07o, but concentrations above this level will occur in the i mmediate vicinity of the cell tops. BS6133 Appendix A gives a typical calculation to arrive at the required number of air changes. The number of air changes is arranged to dilute the average concentration of hydrogen to less than 107 0 . The ventilation outlets venting to the open air are at the highest level in the battery room. Ceilings are sloped towards them, to aid the escape of hydrogen. False ceilings and unvented structural pockets in ceilings are avoided. Air inlets are usually provided at the bottom of the room on the opposite side from the outlets to ensure that air recycling cannot take place and that the ventilation flow is through the room and across the cells themselves. Where mechanical ventilation is unavoidable, fans must be acid-resistant, with totally-enclosed motors, and installed at the outlet of any ducting which itself is made of materials resistant to acid corrosion. It is essential that the ventilation system on the outside of such a room is exclusive to the battery room. 2.4.4 Lighting
It is normal practice to provide corrosion-resistant luminaires in battery rooms. Mounting directly over cells is avoided, to prevent accumulation of hydrogen in the luminaire with consequent risk of explosion. 2.4.5 Battery main connections in battery rooms
2.41 Ambient temperature Since battery capacity and performance is reduced by low temperature, a minimum electrolyte temperature of 5 ° C is maintained as a general rule. However, in nuclear power stations, where reduced capacity could affect the safe shutdown of a reactor, a minimum temperature of 15 ° C is maintained by thermostatically controlled heaters of the totally-enclosed tubular type. Whilst batteries are capable of operating in an ambient temperature of 35 ° C, with occasional excursions to 40 ° C, these high temperatures are avoided, as they
Connections within the battery rooms and to the outside are made of suitably-sized solid copper rod identified at intervals with acid-resistant red/black paint (or tape) for positive/negative connections, respectively. They are supported on suitable stand-off insulators mounted on battery room walls or on extensions of battery stands. The supports are designed to withstand the electromagnetic forces experienced in the event of an inadvertent short-circuit. The main connections to the DC switchgear are taken from the battery via through wall bushings to a top757
Emergency supply equipment
Chapter g ROOF SLOPED TO AID VENTILATION
VENTILATION AIR TO ATMOSPHERE //1.-
8,7
BATTERY SINGLE ROW DOUBLE TIER At_
OF DOUBLE ROW DOUBLE TIER STANDS
BATTERY DOUBLE ROW DOUBLE TIER STAND
1900 MIN
SINK :BENCH
BATTERY ROOM PLAN
FIG. 758
9.3
Typical layout and environmental requirements of a battery room
Batteries
WALL BUSHING
PITCH
11.1
—
1—T7 M
iII
IrnmrnmH
THIMJIMMI
\wrinom
1-71-7
LENGTH = NUMBER OF CELLS X PITCH
-4
105 CELLS
2 X DOUBLE ROW SINGLE TIER
25 DELLS 2 X DC,I,BLE ROW S 1 NC,LE -7,E,
.4— 100 MIN
80
120
160
200
• 240 '
320
480
100
150
200
250
300
400
600
134. 203 1 423 •
172 203 423 249 178
210 203 423 306 216
248 203 423 369 256 228
1689 2136 400 1 400
2592 400
447 1860 680
598 2492 680
735 3024
3072 400 2736 407 886 3584
286 203 423 434 292 228 3504 400 2736 445 1042 4088
362 203 423 584 368 228 4416 400 2736 521 1402 5152
1005 1960 1970
1345 2492 1970
1653 3024 1970
680 3192 724 1993 3584 1970
680 3192 832 2344 4088 1970
680 3192 ' 954 3154 5152 1970
BATTERY CAPACITY An) AT 3 HOUR RATE AT 20C
•
11.1
ELEVATION 'B - El'
BATTERY CAPACITY (AR) AT 10 HOUR RATE AT 15:C LENGTH WIDTH CELL HEIGHT DIMENSIONS HEIGHT kg ' PITCH FACE TO FACE PITCH EDGE TO EDGE FACE TO LENGTH WIDTH FACE 24 CELLS SINGLE ROW EDGE TO LENGTH DOUBLE TIER EDGE WIDTH WEIGHT kg FACE TO LENGTH FACE WIDTH 54 CELLS DOUBLE ROW EDGE TO LENGTH DOUBLE TIER EDGE WIDTH WEIGHT kg FACE TO LENGTH FACE WIDTH 105 CELLS 2 X DOUBLE ROW EDGE TO LENGTH DOUBLE TIER EDGE WIDTH WEIGHT kg FACE TO LENGTH FACE WIDTH 125 CELLS 2 X DOUBLE ROW EDGE TO LENGTH DOUBLE TIER EDGE WIDTH WEIGHT kg —SINGLE ROW FACE TO FACE ST1LLAGE MOTH EDGE TO EDGE
BATTERY Sw1TCHGEAR
'
186 140
1953 2240 1970
2325
FACE TO I LENGTH 1 FACE , WIDTH LENGTH EDGE TO 1 EDGE WIDTH WEIGHT kg FACE TO LENGTH WIDTH FACE EDGE TO LENGTH EDGE WIDTH WEIGHT k.
680
257 , / 368 682 106 267 •
880
900 . 1 307 , 368 i 682 156 317
1100 : 1 357 . 368 682 190 367
I
3192 ' 3192 3192 2058 2274 1 2518 2615 3213 3875 4557 5132 2648 3456 I 4096 4672 5888 ! 1970! 1970 1970 19701 1970 3648 3648 3648 I 2058 2274 1 2518 3113 3825 4613 5425 7300
.
1120
1360
1400
1
1
600
700
2000
433 368 682 1 240 1 443
509 368 682 290 519
585 368 682 340 595
193
393
393
•
I 370
370 7210 2390
I
1
I
•
• 720 •
11130 8550 1 2390 ! 1 ! 13250 ,
I
370
370 435 8560 9910 11960 1 2390 2390 2390 10610 2650 16380 19950 I 25200 10150 I 11750 4180 2390 2390 2390 1 12580 2650 23750 30000 19500 J
'
370 370 510 585 1 4015 16055 2390 ! 2390 1 0610 10610 3250 _. 2650 3 0450 35700 19040 1 6610 2390 2390 1 2580 12580 3250 2950 i 3 6250 . 42500 I
ALL DIMENSIONS IN mm
Hu. 9.3
coned)
Typical layout and environmental requirements of a battery room 759
Emergency supply equipment
Chapter 9 MINma
entry fuse switch unit mounted immediately outside the battery room. Cable connections to the respective chargers or distribution boards are all made at the bottom of these fuse switch units. 2.4.6 Access to battery rooms
Access doors to battery rooms should be locked from the outside of the room at all times, except when work is carried out within the room. Emergency exit doors must be provided with a quick release device on the inside, operative at all times, even when locked from the outside. To prevent damage to cells, battery rooms must not be used as access routes to other areas.
2.5 Initial tests, charging, maintenance and site testing The capability of a battery system to meet emergency demands throughout its life depends on the condition and state-of-charge of the battery installation. CEGB guidelines ensure that operators can have confidence in the capability of a battery to meet an emergency demand. Plante cells basically deliver 100% capacity after initial preparation and charging. Their end of life is not predictable by relating capacity to years of service. They would normally deliver 100% capacity throughout their life which, if they are on charge/discharge cycling operation, can be in the order of 500/600 full cycles. On float charge service, the life is usually dependent on the manner in which the cells are managed. It can be judged from the physical state of the battery, coupled with knowledge of cell electrolyte, specific gravities, voltages and related data. Such data can best be assessed by a specialist from the CEGB or by a manufacturer. 2.5.1 Tests in manufacturer's works
Tests on batteries in manufacturer's works can be divided into two categories: • Type tests.
the emergency loads specified for the particular battery, During the discharge, records of voltage, temperature and specific gravity are taken and plotted against time At the end of the discharge, the cell voltage must be such that, for a complete battery of such cells, th e total voltage must not be less than that specified. The cells used above are then charged at the specified starting rate to a cell voltage of 2.3 V and from thi s voltage at the specified finishing rate to a cell voltage of 2.7 V. Voltage, temperature and specific gravity are recorded and plotted against time. The time required to charge the battery must not be longer than that spe, cified. Starting and finishing rates are given in Section 2.5.3 of this chapter. During the foregoing tests the specific gravity must be maintained within specified upper and lower limits. Electrolyte must not be added during discharge. After charging the specific gravity may be adjusted to the specified normal figure. In order to ensure that the cell lid is correctly bonded to its container, an air leakage test at an appropriate pressure is carried out. No loss of pressure must take place over a specified period.
Routine tests Apart from a visual examination, the only routine test carried out on each cell in the manufacturer's works is the air leakage test described above. 2.5.2 Tests at site
After erection and initial filling with electrolyte and charging, a discharge test to demonstrate the 3 h rated capacity is carried out on each battery. For this, the manufacturer provides a resistive load frame, as it is unlikely that load is available in the power station at that stage. A discharge characteristic of voltage against ti me is plotted. On completion, the battery is fully recharged. Further tests are carried out in conjunction with the associated chargers and are described in Section 4.4.4. of this chapter. 2.5.3 Charging
• Routine tests.
Float charging Type tests are usually carried out on a representative sample of cells of a new design and provide a means of proving the design characteristics. Routine tests are less searching in character and are usually confined to establish that a cell has been assembled correctly.
Type tests Dependent on the total number of cells, one or more cells of each type and size are fully charged. After a period of not less than 12 h and not more than 18 h during which the cells are disconnected from the supply, they are subjected to a discharge appropriate to 760
The method of operation for all the battery systems is known as 'float charging' which means that the charger, the battery and the DC standing (i.e., continuous) load are all connected in parallel. The charger
output voltage is such that the battery voltage is held constant at a voltage of 2.25 V per cell. This is the optimum floating voltage, resulting in the longest possible life allied to the minimum maintenance requirements. Assuming the battery is fully charged to begin with, it will take sufficient 'trickle' charge from the charger at the above voltage to ensure it is maintained in a fully charged condition.
Batteries The charger is sufficiently rated to supply the DC otern standing load and recharge the battery. The s purpose of the battery, with the charger in service, „'-) l e i s to su pply any peak loads such as circuit-breaker osine solenoids which are in excess of the charger , city. The capacity removed from the battery by rhese short duration loads is normally replaced by the utomatically. However, emergency or acci,;11,1r2er a Jental discharge in excess of 5-10% of the 10-hour of the battery may over-discharge it; r ated capacity boost charging would then be required.
Boost charging The quickest and best way of recharging a battery after a discharge amounting to more than 5-10% of the 10-hour rated capacity of the battery is to raise the battery cell voltage from its floating value of 2.25 V to a maximum of 2.7 V. This is commonly known as 'boost harging'. It involves isolation of the battery and its c associated charger from the load, because the voltage imposed on the load may exceed the upper limit of its design voltage. At the commencement of recharge, the charger input current to the battery is limited to 14% of its 10-hour capacity, called the starting rate, up to a cell voltage of
2.3 V, i.e., the gassing point. The current is then manually reduced to 7% of the 10-hour capacity, called the finishing rate, for the remainder of the recharge in order to li mit the amount of gassing from the cell and to pre.ent damage to the plates. Charging is continued, taking specific gravity and voltage readings, until they become sensibly constant over a period of three hours and all Lens are liberating gas bubbles in similar amounts. The system is then returned to normal float charge. Boost charging enables a fully discharged battery to he recharged in 10.5 h, whilst a battery discharged at the 15-minute rate would be completely recharged in approximately four hours. The length of time taken to recharge a particular battery obviously depends on the am pere-hour capacity taken out of the battery during the emergency discharge, i.e., the load, the duration and the final battery voltage at the end of the discharge. An important point to note is that a battery can he over-discharged and permanently damaged. The DC loads must be disconnected at the end of the design duty to prevent any possibility of this occurring. Batteries must not be discharged past a specific gravity specified by the manufacturer, typically 1.170.
age is always less than the gassing point of the cell at 2.30 V per cell. Stratification produces a higher specific gravity at the bottom of the cells than at the top because the water in the electrolyte has a tower density than the acid. This stratification will eventually disappear after about one to two months with continual float charge at 2.25 V per cell and the electrolyte will become fully mixed, providing further discharges have not taken place. A further objection to this method of charging is the increase in time to achieve a fully charged battery. The following approximate recharge times could be expected: Previous discharge, as a percentage of normal battery capacity at 10-hour rate, %
Recharge time (hours)
25 50 75 100
10 24 42 72
As the charger automatically maintains the float charge rate at a nominal 2.25 V per cell (see Section 4.2.2 of this chapter), the battery would be approximately 76% recharged in 12.5 hours, but it would take a considerable time to put back the remaining percentage capacity to restore its full capacity for emergency use,
,
Limited voltage recharging Instead of boost charging after an emergency or accidental discharge amounting to more than 5-10% e! the 10-hour rated capacity of the battery, it is possible to recharge a battery fully at a limiting voltage of 2.25 V per cell, but this is not ideal and is not r e c ommended. Recharging under these conditions may produce stratification of the electrolyte, as the battery cell volt-
2.5.4 Factors affecting cell life and precautions to be taken
Loss of active material from the plates due to cyclic service Lead-acid cells shed active material in service: when the mud spaces below the plates are full of debris, creating short-circuit paths between plates, the whole battery should be replaced. A correctly designed battery, when on float charge, should be time expired before the mud spaces are filled. With clear transparent cell boxes, it is possible to examine the state of the plates and separators at the edges of the cells and to check the rate of sludge buildup in the mud space. The end of life would usually occur when either the sludge has built up to the plates in at least one cell or there are other indications of failure. It is usual for cells to be installed in the edgeto-edge orientation, i.e., the plates are at right angles to the lines of cells to facilitate inspection. Separator failure could cause partial internal shortcircuits: examination of cell electrolyte specific gravity should indicate this. Corrosion at the acid/air interface
Corrosion of pillars, group bars and risers at the acid/air interface is an indication of age. Great care 761
--■1111111 Emergency supply equipment is required when carrying out such examinations, since it is not unknown for the riser to appear normal on visual inspection, but for it to collapse and fail when disturbed.
Chapter 9 An inspection routine is usually based on th e following:
• Daily
Check overall battery voltage.
Check voltage and specific gravity on selected pilot cells per battery, always using the sam e cells. Electrolyte levels are noted and recorded and topped-up, if necessary. A minimum of two pil ot cells per battery are used dependent on the size of the battery and are evenly spaced throughout th e total number of cells, e.g., 1, 30, 60 and so on.
• Weekly Corrosion of terminals and connectors Corrosion of terminals and connectors can occur, but is avoidable since they are accessible for cleaning, inspection, preservation and continuity testing.
Failure of the cell container Safeguards against such failures are: • Regular inspection of pillar seals and lid/case seal. • Administrative control of door locks to reduce the risk of accidental damage, e.g., by battery rooms being used as access routes.
Check voltage and specific gravity, and visually inspect every cell.
• Quarterly
Employ the services of a specialist to assess battery and experience over the year.
• Annually
• Six yearly
See Section 2.5.7 of this chapter.
Contamination of electrolyte
2.5.6 CEGB experience
Electrolyte consumables, hydrometers, etc., must be subject to quality assurance control. Procedures are specified and care must be taken to adhere to them.
It is CEGB policy to follow a pattern of routine inspection, but the exact routine varies from station to station. Some stations employ manufacturers to assist in the assessment of battery conditions. Generally, the CEGB has followed the recommendations of the specialists regarding battery replacement and overall experience has shown this to be a conservative policy in that there is no record of a battery failing to fulfil its required duty. Equally, the record of battery life of up to 30 years has been satisfactory.
Progressively increasing need for make-up water A change in the make-up water rate is indicative of a change in cell chemistry and serves as an indicator for detailed examination.
Degree of undercharging or overcharging Correct battery voltage is necessary to obtain maximum life from an installation. Chargers are checked regularly to ensure that the correct float voltage is maintained.
Boost charging The condition at any time and the ultimate life of an emergency supply battery is influenced by its state of maintenance. A boost charge every 2-3 years is usual. The rate and duration of a boost charge follows the particular manufacturer's recommendations. Details of the boost charge schedule are included in the operating instructions.
Duty cycles The number of charge/discharge cycles in service as ‘vell as the type of duty can determine the ultimate life of a battery installation, which has otherwise been maintained correctly.
2.5.5 Inspection The state of the battery is a good indicator of general conditions of the DC system and its associated chargers. Regular visual inspections are a reliable guide to battery condition and its ability to perform correctly when called upon in an emergency. 762
2.5.7 The case for testing Experience with Plant cell batteries has been sound and it is known that cell capacity does not drop until end of life. Nevertheless, it can be argued that discharge testing to establish the capacity of a battery is a more certain demonstration of its ability to perform satisfactorily. However, testing only demonstrates this at the time of test and at all other times reliance has to be placed on the inspection routines. In view of this, the CEGB does not consider it worthwhile to conduct routine discharge tests, for the sake of the battery alone (see Section 2.5.10 of this chapter for DC system tests). It is important, therefore, to ensure that the inspection routines previously outlined, are sufficiently rigorous and are capable of accurately determining the state of the battery. This can be attained more positively by removing one or two cells for dismantling, followed by closer inspection of all the parts by a
specialist. The CEGB recommends that two sample cells are removed from a battery at six-yearly intervals (or at more frequent intervals, e.g., annually, if the normal inspection shows that unusual deterioration has taken place and that such a check would be prudent). These removed cells will be unserviceable after the inspection and therefore new replacement cells will be required to complete the battery.
Battery systems er removal from the battery, but prior to disr, the removed cells are subjected to a capacity iiara ii i ck at the half-hour rate from a fully charged state. .hhe e half-hour rate is used, since it generally approaches 'I- , juzv ode for which the battery has been installed. 01 The above Policy has been agreed with the Nuclear 111,1allations Inspectorate for all CEGB nuclear power f
A t
l
The points to be examined and the acceptable conJitions are given in Table 9.1. The conditions in this pplicable to any plate in either of the removed r.ible are a LeHs. If an adverse condition is identified on one plate I one cell only, then a further examination of the Nutery will be conducted. Only if this additional exJirination shows the adverse condition to be present n other plates, should the action indicated for the o ondition in Table 9.1 be followed.
tests of essential battery-backed DC systems. These tests, which provide a demonstration that the whole DC system operates within design limits and can meet its performance specification, can also be used to Rive back-up information on the condition of the battery. The case for testing Plante cells has already been discussed in Section 2.5.7 of this chapter, and the point was made that a test is only a demonstration at the ti me of test. Nevertheless, if a system test is to be carried out, it can be used to give support information on the Plante cells. It must be emphasised that this is not an essential test to determine the state of the battery. The test procedure outlined in Chapter 1, incorporates three phases:
o
2.5.8 End of life %, previously described in Section 2.5.6, the CEGB has followed a conservative policy on replacement of batteries and has also achieved acceptable battery life. This policy is continuing. In addition, the requirement to reinoe cells ensures that a closer inspection can be given. ‘k hen the cells reach the conditions indicating that the battery capacity is likely to fall before the next full inspection is due, steps are taken to replace the battery. In general, the practice is to replace the battery when the need for a one-yearly inspection is identified (see Table 9.1) as a result of the procedure outlined in Section 2.5.7 above. If conditions prevent this practice being followed when an annual inspection is required, hen a discharge test at the load duty cycle may be performed on the complete battery at not greater than ± early intervals, to help to decide whether replacement may be deferred for the time being. During the period between discharge tests, the items checked during AR annual inspection are rechecked every six months, inee any deterioration in battery condition could affect ,
lmttery capacity. 2.5.9 Uncharacteristic behaviour of odd cells
Occasionally, it may be discovered that one or two cells symptoms that are not typical of all the other ,ells in a battery. This uncharacteristic behaviour of odd cells should not necessarily be taken as an indication of the unacceptable condition of the whole battery. These odd cells will be discovered by the inspection routines. The cells exhibiting non-typical behaviour should be replaced by new cells. The reason for the behaviour should be determined to ensure that the 'hole battery is not affected. 2.5.10 System tests of essential battery-backed DC systems
Chapter 1 sets out a test procedure for periodic system
• Phase 1 — initial setting up. • Phase 2 — application of emergency load to battery. • Phase 3 — recharge of battery. During the test, the battery parameters shown in Table 9.2 are recorded.
3 Battery systems 3.1 Introduction DC'systems are provided for the following three categories of equipment: • Essential equipment needing a DC supply during normal conditions and also required to operate when AC supplies have been lost, these two categories include: Essential instruments Control Switchgear closing and tripping Telecommunications Protection Interlocks Alarms. • Standby equipment which only operates when AC supplies to normal equipment have been lost, this category includes: Emergency lighting Emergency oil pumps on main plant including turbine-generators and reactor gas circulators, etc. Other miscellaneous emergency drives.
3.2 Provision of DC systems In order to satisfy the categories of equipment listed in the previous subsection, the following DC systems are provided. 3.2.1 220 V DC systems for switchgear closing
It is generally not economical to supply closing solenoids from a battery shared with other loads, such as 763
I
Capacity (nominal) See Note 1
2
(a)
(b)
4
Group bar corrosion Lug/group bar interface on any plate
Positive plate growth Width
(b)
Height See Note 2
C1 I
< 40%
50%
Group bar/pillar interface on any pillar
(a)
1 00u/ii
Ci = -T
Sludge space a/ii of height to negative plate filled
3
Inspection in 2 years
Inspection in 6 years
Item
75%
of conducting area of joint still available of conducting area of joint still available
Inspection in i year
1 00%
(71
I
1 00%
Replace battery it CI < 100% T
40 0/0- 60%
60 0/u-80%
> 80 0/G
50-25%
25-15%
Lug detached or < 15%
75-60N
60-50%
Pillar detached or < 50%
5 mm gap to the case
Between 5-2 111111 gap
Between 2-1 itun gap
At least a 5 mm gap to same level as the negative plate
Between 5-2 rum gap
Between 2 mm and same level as negative plate
• Sealing or lid lifted • Cracked case • Plate touching the ease sides • Plate buckled causing causing short
Potential shorting
5 (a)
Edge/bottom mossing
(b)
Negative plate expansion
None
None
Any indication Short present
At least 5 mm gap to the separator edge
Between 5 and 2 mm gap to the separator edge
Notes to Table 9.1 High performance Plante
Note I:
Standard Plante
7.5 Ah plate C1 -= 0.50C10 25 100
Ali plate Ct
0.48C
1 0 Ah plate Ct = 0.37C10 25/30 Ah Plate CI = 0.34C 1 0
10
Ah plate Cu = 0.44C 1 0
45/50 Ah Plate Cu = 0.33C
2.1 0 0 / I 5 0 Alt Plate CI
10
-
200 Ah Plate C1 CI is the half-hour discharge rate and C
10
0.31C io 0.30C 1 0
is the ten-hour discharge rate
Note 2: Thickness growth will be detected as a mode of failure under items 3 and 5_
Between 2 min and level with the separator
luawd!nba Aiddns Apueblaw]
TABLE 9.1 Regular examination of cells
Battery systems TABLE 9.2 DC system test procedure
Period — , Batten soliage
Phase l ‘
Phase 3
Every 4- hour
i Every -T hour
Ambient temperature I mmediately prior to commencement of Phase 2
i
4
Every — 2 hour
At start of Phase 2
At start of Phase 3
i Every -7- hour
Every
Battery current
Pilot cells
Phase 2
; hour
(b) Electrolyte temperature
Every ; hour
i Every —,- hour i Every -7 hour
(c) Voltage
Every
1 Every -1hour :
(a) Specific gravity
Specific gravity, all cells Voltage, all cells
emergency lighting, emergency DC drives, etc., because He solenoid operating range is between +5% and
- 15n of the rated voltage, whereas the voltage range of emergency lighting is ±20% and of motors ± 10% continuous; —20% for 30 minutes. If the whole DC were designed around the closing solenoids, then the battery capacity would need to be considerably higher, typically twice the capacity without the closing 'solenoids since the designed voltage range would be much less. It is therefore generally more economical to provide dedicated batteries for switchgear closing .olenoids.
Since BS5311 gives 220 V and 250 V as preferred soilage ratings of solenoids, the CEGB chose the kisser, permitting 105 cells to be used for the 220 V 'solenoids instead of 120 cells at 250 V. A dedicated battery for switchgear solenoids also offers a distinct advantage with respect to iblackstare ,apability, i.e., complete loss of AC supplies to the ,hargers as the result of a Grid failure. Under these conditions, switchgear could be operated or many hours, or even several days as no standing loads are connected to the battery. A shared batter!, would usually only be designed for a 30-minute capacity. The system is designed to meet the following criteria:
!T hour
At or near the end of Phase 2, if duration of the phase permits
At end of Phase 3
breakers simultaneously at the commencement of battery discharge. Additionally, it must be capable of closing all other designated circuit-breakers, such as interconnectors and emergency pumps, to shut down the station in a safe manner and to restore the supplies following Grid reconnection. The minimum discharge voltage at the end of this duty must not fall below 199 V at the battery fuse switch terminals. Following this duty and after restoration of the charger supply, it is assumed that no loads will be connected for 10 hours in order to achieve full readiness to meet duties (a) and (b) above. It should be noted that this system is not necessary if switchgear closing solenoid mechanisms are replaced by motor-wound spring-charged closing mechanisms. The advantages and disadvantages of this choice are discussed in Chapter 5. 3.2.2 110 V DC systems for switchgear control, protection and interlocks
These systems provide a secure DC supply for essential loads, such as: • Switchgear and controlgear tripping.
(a) With the battery on 'float charge', it must be possible to close any two circuit-breakers simultaneously.
• Switchgear closing, where spring-charged closing mechanisms are used.
(b) With the battery on 'float charge', it must be possible to close up to 100 circuit-breakers each day. There must be sufficient spare capacity in the battery rating to avoid having to boost-charge it to meet this duty.
• Interlocks and protection.
(c) Following a loss of AC supply to the charger, the
battery must be capable of supplying the solenoid of the highest current-rated single 11 kV circuitbreaker continuously for 30 s or two 3.3 kV circuit -
• Local control equipment and essential instruments. Each battery is designed to be capable of supplying its designated standing and emergency loads for a discharge period of 30 minutes following complete failure of all incoming AC supplies, Additionally, each battery is also capable of supplying one-half of its designated standing load for a 765
-4111111111 Emergency supply equipment discharge period of one hour following loss of a charger. This permits a standby charger to be connected manually. The minimum discharge voltage at the end of these duties must not fall below 102 V at the battery fuse switch terminals. 3.2.3 4-8 V DC systems for telecommunications, plant control and alarms
These systems provide secure supplies for two distinct categories of equipment:
Chapter 9 The minimum discharge voltage at the end of the se duties must not fall below approximately 211 V at the battery fuse switch terminals. In the unlikely event that AC supplies are not restored by means of diesel generators, it is necessary to disconnect loads no longer required to permit the hydrogen-cooled generator emergency seal-oil pump s to continue to operate for a further 1.5 hours. Sufficient spare capacity is allowed in the rating of the battery to avoid having to boost charge it after a 30-minute discharge period with loads as described above.
(a) Telecommunications equipment such as: • Private automatic exchange (PAX) • Private automatic branch exchange (PABX) • Direct wire telephone system (DWTS) • Radio system controllers • Control desk telephone equipment • System operation telecommunications equipment. (b) DC supplies for essential loads, such as: • Automatic sequence control equipment • Alarms and indications at central control room
• Manual control from central control room. Each battery is designed to be capable of supplying its designated standing and emergency loads for a discharge period of 30 minutes following complete failure of all incoming AC supplies. Additionally, each battery is also capable of supplying one-half of its designated standing load for a discharge period of one hour following loss of a charger. This permits a standby charger to be connected manually. The minimum discharge voltage at the end of these duties must not fall below 46 V at the battery fuse switch terminals. 3.2.4 250 V DC systems for emergency lighting and emergency drives
These systems provide secure DC supplies for loads, such as: • Emergency lighting (DC luminaires).
3.3 Duplication of battery/charger systems To allow boost charging and maintenance to be carried out, which requires isolation of the battery/charge r combination from the DC load, they are provided in duplicate with suitable switching facilities at the DC switchboard. These permit the two battery/charger systems to be paralleled before taking one off-load. 3.4 DC system voltage limits Power station DC systems must be designed to lake account of limits of the load voltage. For good battery operation it is necessary to charge at the float voltage, but it is also necessary to discharge the battery down to a sufficiently low voltage, if the full capacity is to be released from the cells. In order to ensure that the conditions at the terminals of any DC loads are consistent with the requirements of Chapter 1, the battery parameters as shown in Table 9.3 are used. TABLE 9.3 DC system voltage limits
System nominal voltage, V
48
110
220
250
No. of lead-acid cells
24
54
105
125
Float charge voltage, V (2.25 ViceII)
54
121.5
237
281.3
46
102
199
210.5
65
146
283
337
Minimum discharge voltage at battery equipment termination, V Off-load boost charge voltage, V (2,7 V/cell)
• Emergency auxiliary drives, such as lubricating oil pumps for turbine-generators, gas circulators, etc. • Emergency valve operation. • Fire sirens. Each battery is capable of supplying the designated total load of all emergency auxiliary drives and the designated total emergency lighting load, excluding plant buildings remote from the main station building, for a discharge period of 30 minutes following complete failure of all incoming supplies. 766
4 Chargers 4.1 Introduction From the remarks made in Section 2.5 of this chapter, it will be evident that a correct charging procedure is most important to ensure satisfactory battery life and performance. Modern charging equipment, using AC supplies, provides safe and flexible control of battery
Chargers harving either automatically (float charging) or with minimum of manual attention (boost charging). t he yell as maintaining the battery at a sufficient state As the charger must also be capable of supontinuous electrical system load (standing c q peaks and emergency loads to be supplied i Ica\ n the battery. De performance targets of a battery charging system
.
1L
„ hca‘y duty lead-acid Plante cells in a power station summarised as follows: be
that the battery is maintained at a suffi• To ensure j,: nt state of charge, without reducing its life or necessitating undue maintenance.
that the output voltage and current of the • To ensure mplete system are compatible with the connected electrical load. o
•
To ensure that adequate system monitoring is available to tile appropriate interface standards.
• To ensure that the battery is recharged after a discharge, sufficiently to perform the specified discharge duty within the specified recharge time.
42 4.2.1
Required characteristics Initial charge
In he manufacture of the lead-acid battery, the plates
,ire converted to the active state of lead dioxide (posi-
:i%e plate) and spongy lead (negative plate) in the precnce of dilute sulphuric acid during a process known i the formation charge. Following formation, the plates are washed and dried .ind assembled into cells or batteries. After adding ,illine sulphuric acid, and before putting into service, essential to give the battery an initial charge. This ,om.ists of passing a current into the battery for a :l umber of hours, as recommended by the battery ::1,11,er. This charge completes the electrochemical con%,.r,ion of any lead sulphate remaining in the plates. Ii ensures that the battery starts its life in the best ;Thsible condition, so that it is capable of giving rated ..ipacity and satisfactory performance from the moTon it goes into service. It also ensures maximum life. I he initial charge is given to the battery either in the 'tlanufacturer's works or on site (see Section 2.3.13 oi this chapter).
large increase in current. Once the open-circuit losses have been overcome any more current is unnecessary for charging and is undesirable (see Section 2.3.15 of this chapter). Equally, if the voltage is allowed to fall too low, the open-circuit losses will not be replaced and the battery will slowly discharge. Thus the charging voltage needs to be carefully controlled for proper battery maintenance. The limits used by the CEGB are +1 01} about the float voltage for a charger load between ON and 100 070 of its rated current. The float voltage has a small negative temperature coefficient which must be allowed for when batteries are to be used in exceptionally hot environments. CEGB power station chargers are provided with a stepless float voltage adjustment from 1.69 V to 2.4 V per cell mounted inside the charger cubicle to prevent unauthorised access and possible maloperation leading to over or undercharging of the battery. 4.2.3 Charger ratings
In the simplest DC standby power system, the battery is permanently floated across the system or load in parallel with a rectifier charger. The float charge rating must therefore be capable of supplying the sum of: • The float charge rate of the battery. • The continuous (standing) load of the system. In practice, the chargers for CEGB power stations have to fulfil further duties to provide continuity of supply, and the systems described in Chapter I have been developed to ensure this. Summarising these duties, the float charge rating must be selected from the sums of one of the following two systems.
Interconnected unit system • The float charge rate of the batteries of two unit systems. • The standing load of two unit systems. • One half of the station system standing load.
Interconnected station system • The float charge rate of two associated batteries. • The standing load of the whole of the station system.
4.2.2 Maintaining charge
If the initially charged battery is left disconnected from
L'ad or charging equipment, it will slowly discharge. In order to maintain the charge without excessive cur• flow, the charger output voltage must be held onstant at 2.25 V per cell, to replace the small open ,..1r [ losses.
In addition to the above requirements, chargers must be designed to operate satisfactorily in parallel, to ensure changeover on-load before a charger is taken out of service.
,
ihe current/voltage characteristic is non-linear, i.e., A small increase in charging voltage causes a relatively
4.2.4 Boost charging There are circumstances when the float voltage can and should be exceeded. New batteries, those which 767
Emergency supply equipment have suffered abuse, or those discharged by 5-10% of their 10 h rated capacity will benefit from vigorous gassing at up to a boost voltage of 2.7 V per cell. For this purpose, a separate constant voltage, variablecurrent charger can be provided in addition to the float charger; or the facilities can be incorporated in the float charger. Whichever method is used, boost charging must only be carried out with the battery disconnected from the system to avoid applying excessive voltages to equipment on the load side of the charger. To ensure this, a float charge/boost charge selector switch must be provided and interlocked so that the system load must be disconnected before boost charging. Since boost charging is always carried out under supervision the charging current is regulated manually. The control potentiometer for this purpose is mounted inside the charger to prevent unauthorised access. 4.2.5 General additional requirements
Output voltage ripple It must be possible to operate chargers without batteries. Under this condition, the DC voltage ripple must not exceed 10 07o peak-to-peak of the battery float voltage under loading conditions over the range 0 to 100% rated output.
Power supplies The following power supplies for the input to the chargers are normally provided in a power station: • 415 V, three-phase, 50 Hz, solidly earthed neutral. • 240 V, single-phase, 50 Hz, solidly earthed neutral. In general, the 415 V three-phase supply is preferred to allow distribution of the load evenly across the phases, but the 240 V single-phase supply can be used to an upper limit of 16 kVA. The supply is normally maintained within + 6% and - 10% of the nominal voltages and within the frequency range of 49.5 to 51 Hz. Chargers must be capable of continuous operation at their rated output with any combination of the above voltage and frequency limits. In addition, chargers must be capable of continuous operation over the above voltage range at an output which decreases pro rata with frequency below 49.5 Hz down to 47 Hz. Operation below 48 Hz will not be for periods longer than 15 minutes at any one ti me.
Supply voltage transients Chargers must be capable of operating from a supply voltage which is 20% low for up to 90 s to cover the starting of large motors, the frequency being within the limits of 47 to 51 Hz. Under these conditions, 768
Chapter 9 the charger must not be damaged, nor must it m a i_ function. During extreme transient conditions caused by ex ternal system faults, the voltage at the supply terminals to the charger may be lost for up to 0.2 s, followed by initial recovery to 60% for 3 s and then 80% fo r a period not exceeding 3 min. Under these conditions, the charger must not be damaged, but its probable performance, whilst not critical, must be assessed by the manufacturer.
Rectifiers Rectifiers used in CEGB power stations are of the full wave bridge type, employing either silicon junction diodes or thyristors. In order to ensure a long life for the rectifier it is vital that the junction temperature of the diode/thyristor is limited. In order to achieve this, the diode/thyristor and heat sinks must be rated by the manufacturer to carry 200% of the load current continuously when operating in an ambient air temperature within the cubicle of 55 ° C, without exceeding the maximum junction temperature of the diode/thyristor as quoted by its manufacturer. In other words, under normal operating conditions the diode/thyristor is only half-loaded, with a considerably reduced junction temperature. Internally to each charger, individual diode/thyristor fuses are fitted to provide protection in the event of diode/thyristor failure. They are special high speed fuses, specifically designed for use with semi-conductor rectifiers because of the latter's low I 2 t capability. These fuses are provided with striker pins which, when the fuse ruptures, operate a microswitch to illuminate a warning lamp to locate the rectifier arm in which failure has occurred and give an alarm (see Section 4.2.8 of this chapter). To protect the rectifier against voltage surges, inverse or otherwise, from the input or the load that may occur in service, surge suppression circuits are incorporated and fitted with alarm type fuses as described above.
Transformers and chokes These are usually of the naturally air-cooled type with class F non-hygroscopic insulation to BS2757. In order to ensure a long life, the temperature rises are li mited to those appropriate to class B insulation. To allow for input voltage adjustment, bolted links are fitted to permit voltage variation of + 5% in 2-,L n steps.
Electronic equipment All electronic equipment is designed to comply with the CEGB General Specification for Electronic Equipment, EES 1980, suitable for Class B3 conditions with ° an ambient temperature range of 0 ° C to 40 C outside the cubicle. The electrical environmental class is taken as X which is 'mild' and generally applicable to plant rooms.
Chargers
4.2.6 Earthing power . systems at 110 V and above II. pc standby itive and negative poles insulated from earth. pos earth leakage detection system is provided incoro, a resistor connected across the battery and . , , ,, j entre tap to which a detection relay is connected ac Jr[h,this ensures that an earth fault occurring on role i , h , ,,stem does not blow a fuse, but can c rcadiY detected for remedial action before another fault occurs. Fuses for outgoing circuits are „jed in the positive pole and withdrawable links ; ,.. „ ‘ he negative pole. as V DC standby power systems have their positive solidly earthed. Fuses for outgoing circuits are , prorided in the negative pole only.
• Battery earth fault. • Battery voltage low.
\
4.2,7 Protection and monitoring ().ervaltage protection Char,ers are provided with an integral voltage sensjerice, measuring voltage at the charger output rerminals. Should this voltage rise significantly above normal float voltage of the battery, the circuit is Jrranged to shut down the charger and provide an alarm. This device must be disabled during boost ..har4ing. ()lc voltage detection Ic ■sarn of load failure due to insufficient voltage, a roltage detection device is provided to give an alarm. This enables batteries to be disconnected to d wid damage due to excessive discharging. Ilartery circuit monitoring Corrosion of the group bars joining groups of positive or negative plates could eventually lead to an open..:r,:uited battery if not detected in time by !egular
p,:ction. Modern CEGB power stations are fitted . ■ Ii h battery continuity monitoring devices to provide .11 alarm if an open-circuit occurs, which could seriousH jeopardise important DC supplies, e.g., switchgear
4.2.8 Alarms Fach charger is provided with the following alarms %.0lich can be displayed by indicating lights or alarm iaLias on the charger cubicle: • Charger failure (loss of AC supply). • Charger shutdown on DC system overvoltage.
• Battery on boost. Since charger cubicles are generally located in unattended rooms, it is important that the central control room is made aware when any of the above faults occur. Usually, the control room engineer cannot take direct action to rectify the fault and can only direct an auxiliary plant attendant to investigate locally. The above alarms, with the exception of 'battery on boost' and 'battery open-circuit', are therefore grouped on a common facia in the central control room titled 'battery/charger fault'. This keeps the number of facias within bounds and reduces the workload of the control room engineer. The 'battery on boost' and 'battery open-circuit' alarms are considered sufficiently vital for the control room engineer to be informed separately, to indicate that the battery is not available for load or to enable him to take more urgent action. 4.2.9 Nuclear safety
In the event of a seismic disturbance, whilst it may not be feasible to continue to operate a nuclear reactor on load, it must be possible to shut it down safely and avoid a nuclear hazard. In such an event, batteries and chargers play an important role, since there may be a complete failure of Grid supplies. All equipment involved must therefore be designed and tested to withstand a seismic disturbance of specified severity.
4.3 Description of equipment 4.3.1 Introduction
In order to fulfil the requirements outlined above, chargers of varying ratings are provided for the many
diverse loads and battery capacities. The equipment for an individual charger is usually contained in a ventilated steel cubicle with a hinged front door; it can be divided into the following groups: • Magnetic components and filters, e.g., main transformer, DC filter choke and filter capacitors. • Thyristor and diode stacks. • Control board. This printed circuit board comprises all circuits for the control of the rectifier and alarm systems.
• Surge circuit fuse failure.
• Display. This is normally fitted to the door and gives visual indications of various conditions and alarms, together with facilities for switching.
• User-temperat ure and cooling fan failure (when forced cooling is provided). • Battery open-circuit.
Since most of the components of chargers are similar and vary mainly in size, the details of a typical charger are given in the following sections.
• Rectifier fuse failure.
769
Emergency supply equipment 4.3.2 Basic principles
Chapter g
Figure 9.4 shows a simplified block diagram of a typical charger. Single or three phase versions are available, but the basic principles are similar. More detailed descriptions of some of the items are given in subsequent subsections.
the excitation voltage. During the other half cycle, th e roles of the two reactors are reversed. The resultant output current is an AC near-square wave, proportional in amplitude to the DC prima ry current. This, after rectification, gives the typi ca l notched DC waveform.
k tains
DC filter
transformer
This provides the power for the basic rectifier and isolates the mains from the rectifier. It is designed to give a voltage and current output compatible with the requirements of the battery and standing load. Thyristor rectifier This is similar to a conventional bridge-type full wave rectifier, with thyristors replacing the diodes. Using the control board, the output is controlled by regulating the proportion of time during which the thyristors conduct in each half-cycle period. Control board This printed circuit board monitors various parameters associated with the operation of the rectifier by comparing them with preset standards. The results are used to regulate the conducting time of the thyristors so that the rectifier output voltage is maintained at the correct level. Reference transformer This has two functions: • To provide power for the power supply section of the control board. • To provide a reference voltage for use as a datum in the thyristor control circuits of the control board. DC voltage and current transformers These provide isolated DC outputs from DC sources suitable for use with integrated circuits. The basic DC current transformer consists of two identical saturable reactors connected in series-opposition with a common primary winding. The reactors are toroidally wound on high permeability (square loop) magnetic alloy. Figure 9.5 shows the usual practical circuit. The DC ampere-turns due to the primary current will cause both reactors to saturate. In this condition their AC impedance will be low. The application of the AC excitation current will alter the level of saturation in each reactor. In a given half cycle, the alternating current will drive one reactor further into saturation keeping its impedance low. On the other reactor, the magnetising forces will oppose, tending to remove saturation and current will flow to bring the reactor just out of saturation. The AC impedance of the reactor will then go high and will support the remainder of 770
This is of the normal choke/capacitor type and reduc es the ripple on the output of the charger to an acceptable level. A charger operates permanently into a source of EMF, so current can only flow when the charger EMF exceeds the battery EMF. This could lead to very short periods of rectifier conduction, hence ver y high peak values of current being fed to the load. The DC filter extends the periods of conduction and so reduces these pulse currents, resulting in a considerable reduction in the output current ripple. In addition, semi-conductor components need not be rated to carry these excessive peaks. 4.3.3 Main transformer
This is usually of the naturally air-cooled type with three secondary windings for the three arms of the rectifier. Allowance must be made in the design to allow fo r possible distortion of the voltage waveform due to the presence of the rectifier, which would increase losses and therefore produce a higher temperature rise. 4.3.4 Thyristor rectifier
Thyristors are usually of the silicon type mounted on heat sinks. The larger output thyristors are someti mes provided with forced air cooling to augment the natural cooling and thus keep temperature rises to the manufacturer's specification, while keeping heat sink dimension (and thus cubicle dimensions) within reasonable limits. 4.3.5 Control board
The control circuits can be sub-divided as follows. Voltage feedback This circuit compares the DC output voltage produced by the DC voltage transformer with a preset value and produces a signal to keep the output at this level. With normal load conditions, the voltage feedback circuit fully controls and holds the charger output voltage to the float voltage setting. When the total current limit or the battery current limit is reached, the voltage feedback circuit is overridden and the charger output voltage is reduced by the current limit circuits, thus limiting the output current to the set limit. On switching power to the rectifier, and until steady operating conditions are reached, the voltage output is depressed and steadily ramped up to float voltage by the action of a 'soft start' circuit.
Chargers
TR
THYR1STER RECTIFIER
MAIN AN.5FQ P.M ER
C VOLTS TRANSFORMER
C FILTER I■
SHUNT
117 LOAD
11
4** CONTROL BOAFTD1
FIRING PULSE CURRENT
RENCE FCRMER
FIRING CONTROL
VOLTAGE FEEDBACK
•■ITOTAL CURRENT FEEDBACK
■49■13ATTERY
DC CURRENT
CURRENT FEEDBACK
TRANSFORMER
ALARM SECTION HV LV
POWER SUPPLY
00-
VOLTAGE & CURRENT COMPARATOR
0-
BATTERY DISCHARGE
■1■1•1•••
••••■•
Fir.. 9.4 Simplified block diagram of a typical charger
-
DC PRIMARY 1 CURRENT
1 I
•
■^1,-Y-s
^
IOC CURRENT JTRANSFORMER
AC EXCITATION .OLTAGE
it,. 9,5 DC current transformer — circuit diagram
Battery current feedback
In this circuit, the battery .harging current signal produced by the DC current iransforrner is compared with a preset value. Current t (ceeding this level will reduce the output voltage until this level is reached. ,
2,
Total current feedback This circuit measures the total current fed into the rectifier bridge. Any condition which causes this current to exceed a preset value will reduce the output voltage until the input current is within its limit. Thyristor firing control In this section, the sum of the signals from the three feedback circuits above are related to a reference voltage supplied by the reference transformer. This ensures synchronisation with the mains input voltage. An output signal is produced, which controls the firing point of the thyristors in each half cycle period. This output drives the firing pulse amplifiers. After firing, the thyristors will continue to conduct until the voltage across them falls to zero. Each thyristor therefore requires two firing control circuits, i.e., one for each half cycle, making a total of six for a three-phase group. Firing pulse amplifiers
These are simple oscillators which are switched by the output signals from the firing control circuits. Their electrically isolated outputs are rectified, producing the DC signals required to turn on the thyristors. Similar to the firing control 771
Emergency supply equipment circuits, there are six firing pulse amplifiers for a three-phase group.
Power supply section This is fed from two secondary windings of the reference transformer. Each winding is connected to a rectifier which provides outputs which vary in magnitude from manufacturer to manufacturer, dependent on the design requirements of the control board. Typical values are +18 V and +15 V. These output voltages are fed to the control board via stabilised voltage regulators. They are also available for other purposes as required, e.g., alarm circuits. Alarm section The power supply to this section is fed via a thyristor with a capacitor/resistor delay to allow other power supplies to become stabilised, thus avoiding spurious alarms. The various alarm signals such as high voltage coupled with high battery charging current and low voltage coupled with low battery charging current are generally obtained by a feedback signal fed into an amplifier where it is compared with a preset value. Under normal circumstances, for 'high' alarms, the amplifer output is negative and the output is blocked. If the feedback voltage exceeds the preset value an output signal is produced to energise the alarm on the front panel display. For 'low' alarms the reverse applies, i.e., the amplifier output is normally positive and so on. 4.3.6 Reference transformer
This mains-fed transformer has three secondary windings, two of which provide the power supplies for the control board and the third the reference voltage for the firing control circuits. This transformer is usually specifically designed with specific ratings and connections of the secondary windings to suit a particular rating of charger. It is therefore not interchangeable. It is particularly important that the phase relationship to the main transformer is not interfered with, to ensure the correct order of firing pulses. 4.3.7 DC transformers
The DC voltage transformer obtains the supply for its power section direct from the mains, and a signal from the DC output of the charger. It gives an output proportional to the output voltage of the rectifier to feed the voltage feedback circuit of the control board. The DC current transformer requires an input from the power section of the control board and a signal of the output current of the charger obtained from a shunt. It gives an output proportional to the output current of the charger and feeds the current feedback circuit of the control board. It also provides an indication of the battery discharging in the event of a charger failure. 172
Chapt er 9 4.3.8 Display
It is usual for the front door of the charger to carry the necessary switches, instruments, indication a n d alarm displays to enable the operator to ensure th at the constant (standing) load is supplied correctly a n d that a fully charged battery is available for emergen cy use. The facilities provided fall into three categories, Although they can vary in detail from charger to charger, they generally comprise the following:
Instruments • Voltmeters to register 'input' and 'output' volts. • Ammeters to register 'input' and 'output' current.
Control devices • Input isolator — this switch is interlocked with the front door to ensure that the incoming AC suppl y is off before the door is opened. • Output isolator.
Note: Both the input and output isolator can be padlocked in the 'off' position. Dependent on the current rating of the charger, they can either switch direct or energise contactors or circuit-breakers. • Float/boost changeover switch. • Alarm reset and lamp test pushbuttons.
Alarm devices The manner of displaying alarms varies from manufacturer to manufacturer. The three types most commonly employed are: • Indicating lamps. • Light emitting diodes. • Proprietary alarm facias. The number of alarms displayed varies according to the complexity of the charger and the requirements of the CEGB specification for a particular location. A typical list was given in Section 4.2.8 of this chapter. Facilities are also provided by means of clean relay contacts (i.e., contacts not connected to other circuits) to energise alarms in the central control room, as required. 4.3.9 Battery float/boost control circuitry
The float/boost switch on the front door of the charger can only be operated by means of an interlock key which becomes available for use when the load is isolated. This enables the battery alone to be boost charged. During this operation, the interlock key is trapped in the float/boost switch to prevent the load being switched on.
71
1111.1111110•1"-Chargers
,
n boost is selected, the voltage reference feedautomatically. increased by the float/boost and the current feedback similarly reduced. This raises the current limit to the boost charge i-Jte• During this operation, the charger high
\1/4 h e -k is
I,L
4. 4 4.4,1
Alarm is also automatically inhibited. When reaches the gassing voltage, the current finishing rate. to
Testing Introduction on chargers can be divided into two categories:
manufacturer's works. • rests in at site. ▪ I he former can be further divided into type tests and tests. Type tests are usually carried out on the
unit of a new design and provide a means of the design characteristics as well as the correct ioning of the unit. Routine tests are less searching ' ,l-iaracter and are usually confined to establish the ,orrect functioning only. 4.4.2 Type testing in manufacturer's works usual for the manufacturer to submit to the FGB, for agreement in good time before the tests ! A ke place, a test schedule including the parameters he recorded so that the tests can progress smoothly 1 ,d without any delays. This is important with some 0: the special tests for which the use of an outside et organisation may have to be used who usually on a time basis. In-house testing is clearly prered, but the extremely high cost of special equipment .‘upled with its infrequent use sometimes prohibits , Elie following is a basis for such a test schedule:
• Visual checks. • Performance tests and settings. • •lacm checks and settings. • Instrumentation checks. • Electrical stress. • Output voltage and waveform analysis. • Smoothing checks. • Output cheeks during supply transients and inter-
ruptions.
• Temperature rise test. • Insulation resistance. • Soak test. • Seismic tests (where specified for a nuclear power )ta(ion) .
• Testing of electronic circuit boards and components. • Final visual inspection and performance test. Some of the above items are self-evident, others require further elaboration. Output voltage and waveform analysis, and smoothing checks
The DC output voltage is measured over the load range, including the most onerous specified load range, and a harmonic waveform analysis is produced. Before the tests take place, the manufacturer submits full details of his calculations of the harmonics produced by his equipment. He is required to demonstrate that due allowance has been made in the transformer design for these harmonics and their effect on the transformer losses.
Visual checks A complete physical check is carried out to ensure that the equipment has been provided in accordance with previously approved drawings, that the appropriate clearances to earth and between phases have been achieved, that components are to the normally approved CEGB standards, that the necessary shrouding. against accidental contact has been provided and that the equipment is clean, free of dust and swarf.
Performance tests The voltage and current regulation is demonstrated throughout the specified load range within the specified input voltage and frequency variations, and also transients.
Temperature rise test The charger, as mounted in service with all cubicle doors and covers in position, is subjected to a temperature rise test by either connecting it to a simulated load or, for larger equipments, by short-circuiting the output terminals. When the latter method is employed, full-load current is applied at reduced voltage to simulate load losses. The equivalent of the open-circuit losses obtained from an open-circuit test are incorporated by increasing the current by a proportionate amount. Thermocouples are positioned at hotspots known from experience, such as the top of the inner transformer winding, busbars (particularly joints), thyristor heat sinks, etc. Throughout the test, readings are taken at half-hourly intervals and the test is terminated when two or three sets of readings have been substantially constant, indicating that maximum temperature rise has been reached. During the test, ambient air temperature readings in three positions around the cubicle are taken and averaged, as also is the ambient air temperature inside 773
Emergency supply equipment
Chapter 9
the cubicle. From these and the thermocouple readings, the appropriate temperature rises are calculated and compared with specification requirements. After the temperature rise test, a test is performed to show that the transformer temperature is satisfactory when producing full output in accordance with the most onerous specified duty cycle.
to a series of tests designed to ensure that it has bee n correctly assembled, that the correct components hav e been used and that the equipment functions correctly. These tests comprise:
Testing of electronic circuit boards and components
• Visual examination for similar reasons to that carried out during the type tests.
Electronic circuit boards (control boards, alarm and indication monitoring boards, etc.) are tested in accordance with the type tests listed in the CEGB General Specification for Electronic Equipment, EES 1980. If the same design of a board is used in chargers of different ratings, only one series of type tests is necessary on the printed circuit board. The tests specified ensure that electronic components will satisfactorily operate in the temperature and humidity environments stipulated in this specification. By means of ovens, refrigerators and climatic chambers, they are subjected to high and low extremes of temperature and high humidity as may at times occur in service. They are also subjected to specified vibration levels and drop tests, simulating the dropping of a printed circuit board onto a bench, as may occur during maintenance. Both before and after the tests, detailed performance tests and a thorough visual examination are carried out. Throughout the tests, the printed circuit boards are energised and regular performance checks are carried out to ensure failures are detected at the earliest possible moment to establish any particular weaknesses of the design. Although the above tests c&I be performed with the electronic components in situ in the charger, it is usually more convenient to carry them out separately. Soak test
During this test, the charger, is energised at normal voltage for a continuous period of 100 h, as in service, to detect any 'rogue' electronic components which have passed all the other tests. The final performance test, which is identical to the performance test at the beginning of the type test series, will indicate any deterioration or failure when comparing results. Routine tests as part of type tests
In order to ensure that the routine tests specified for subsequent units are satisfactory and can be performed without serious problems arising, they are carried out on the type-tested unit. Any difficulties arising can then be resolved before the further production units become available, resulting in a saving of time and space in a test bay. 4.4.3 Routine tests in manufacturer's works
On completion of erection, each charger is subjected 774
• Testing of electronic equipment in accordance with routine tests listed in CEGB General Specification for Electronic Equipment, EES 1980.
• Heat run with a limited number of thermocouples attached to hot spots determined during the type tests. • Check on smoothing, insulation, accuracy of instrurnents, correct functioning of switches, indications and alarm contacts. • Insulation resistance of the completed equipment, • Applied high voltage test, followed by a further insulation resistance test to detect any breakdown s that may have occurred. 4.4.4 Tests at site
These are carried out on each charger in accordance with CEGB document 099/500 — Site Testing and Commissioning by Switchgear, Transformer and Reactor Manufacturers. Their main purpose is to establish that the equipment has not been damaged during transit from the factory to site or during erection. They also ensure that the charger operates satisfactorily with its associated battery and external load. The tests can be summarised as follows: • Visual checks for damage, loose connections, missing components, etc. • Presence and values of fuses. • Insulation resistance to earth. • Check that AC supply, connections and fuses are available. • Check that charger operates normally in both 'float' and 'boost' outputs. • Fully charge battery and top up electrolyte if necessary. Connect load equivalent to approximately 50 07o of charger rating. Switch off charger. Check that battery discharges correctly into load (instrument polarities correct, etc.). • Check that low voltage alarm operates. • Switch on charger to 'float' and check that it attains its full rated output and that current limit feature operates. • Recheck with charger switched to maximum 'boost' and check that maximum charger output persists only for a short time before tapering down. • Switch charger to 'float' and check that DC output voltage is within the limits of + 1 07o .
Diesel generators Check operation of high voltage and earth fault •
31 arms.
• Rechaue battery fully, record specific gravity and ol[ae of each cell and leave charger on 'float' to LCP
battery ,:hared ready for use.
5 Diesel generators 5.1 5,1.1 nic , c1
System requirements Purpose of diesel generator installation
,,enerators are required in all types of CEGB -t
er ations to provide back-up electrical supplies to i[Jble essential auxiliary plant to perform its role to • , I t- ch. shut down, and to maintain in a shutdown condi:ion, conventional boiler or nuclear reactor and main '
,i.'nerator plant in the absence of Grid supplies,
For instance, at the Dinorwig pumped-storage power .!.ition, on loss of Grid supplies, diesel generators profor normal drainage pumps, emergency Ic [n,2, battery charging, essential instrumentation, Hh t
In addition they enable a main generator to be arted and to re-energise the Grid system, known as rc -, [ack station start. ; Diesel generators are also specified for the new
p:ricration of 900 MW coal-fired power stations to :a.iititain essential electrical auxiliary supplies during ,h u [ k.10+.5n conditions in the absence of Grid supplies. their most important use, however, is in nuclear i ,,mer stations, where they are associated primarily with !- e.i,ior cooling water and emergency boiler feed systems ;he event of failure to maintain or re-establish Grid IeCtrical supplies during reactor post-trip operation. 1s batteries are half-hour rated, diesel generators in addition, required to supply battery chargers to ;!..in!ain the standing load and to recharge batteries n readiness for a restart of the reactor/turbine-gen-
...-.1!or unit. '•ii nce he installation of diesel generators in nuclear r!h+er stations is their largest and most important 1-). the CEGB, this section gives details of such
no ilat ions 51.2 Starting and loading Her reactor trip conditions (either one or both reor a two-reactor nuclear power station), all g enerators in the station are signalled to start ..titoinatically from the reactor post-trip sequence systo run at preset AVR and governor settings, i.e., ili +.oltage and speed. Such an emergency start over' 'lc' any AVR and governor settings selected manually he control desks. In the event that the reactor trip is accompanied loss of Grid supplies or should these supplies be Mille diesel generators are running on open cir'-un, they will be connected to their respective 3.3 kV -'
Essential Services Boards, having first established that the normal feeds via 11/3.3 kV transformers are open, together with any interconnectors between 3.3 kV Essential Services Boards which might have been closed when Grid supplies were lost (see Fig 9.6). Each diesel generator is associated with its own 3.3 kV Essential Services Board, thus diesel generators will not normally be required to run in parallel with one another. This avoids synchronising delays in bringing diesel generators into action. They must, however, operate satisfactorily in parallel with the station auxiliary system, as described below.
Should a reactor trip occur when a diesel generator is running on test under manual control, but otherwise available for emergency duty, the appropriate circuitbreakers will be tripped and the emergency start relays will reset the diesel generator AVR and governor to the preset emergency running conditions. The diesel generator is therefore available for loading with others, as described above. When a diesel generator has been connected to its 3.3 kV Essential Services Board under reactor trip and loss of Grid conditions, it will be loaded automatically in accordance with a preset sequence. After emergency running, when Grid supplies have become available, each diesel generator will be controlled manually from its control desk. Under this condition, the diesel generator will be selected to parallel running to introduce speed and voltage droop characteristics followed by synchronising with the station auxiliary system energised from Grid supplies. When running in parallel with the Grid has been achieved, the diesel generator is then unloaded and shut down. It will then be available again for emergency duty. This form of parallel running is also a requirement for periodic full load testing of the diesel generator in an operational nuclear power station (see Section 5.4.3 of this chapter). It should be noted that diesel generator auxiliary supplies are generally obtained from the station 415 V Essential System which is subject to interruption of supply for up to 30 s on foss of Grid. Should the diesel generator be running on test at the instant of loss of Grid, it should be capable of withstanding the resultant loss of load, which may be full rated load, and of running through without auxiliary supplies at no load for a period of at least 30 s. Attention is drawn to the need to test the diesel generators easily and also their initiation devices, to ensure their availability as standby plant. 5.1.3 Rating and number of diesel generators
It is normal CEGB practice for a two-reactor station, each reactor having four independent quadrants, to install eight diesel generators to allow for sufficient redundancy in the event of machines not being available due to a maintenance outage, failure, or failure to start. 775
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The continuous maximum ratings (CMR) are based -al the auxiliary system loadings as described in Chapter L Typical of the AGR type figures for the Heysham 2 i lear power station are 5.2 MW for four of the ,nachines and 6.8 MW for the other four. They also 1011) co,erloacl capabilities of 5.8 MW and 7.5 Nivv pectively for 60 .min. unuous rating, each diesel In addition to is t ,enerator is capable of meeting the transient voltage lin j power requirements during direct-on-line startof individual drives with squirrel-cage induction inoors. These requirements include the starting of ihe largest individual drive, such as an emergency boiler f ee d pump motor, at the end of the loading sequence initiated under the emergency conditions described Additionally, the tripping of a block load equia bove. 0 ‘alent to 33 )) of the generator CMR rating must not se a frequency excursion outside the range of 48 cau co SI Hz. The diesel generator systems are engineered to pro\ ije a high degree of reliability and to avoid dependence upon single items of auxiliary equipment. Subject o deterioration or wear or liability to accidental jamage, adequate auxiliary equipment redundancy is ncorporated The diesel generators are suitable in all respects for rapid starting and loading, including 'dead starts', after being stationary for long periods. They are also capable of running a significant number of hours at no-load between periods of routine testing or operation. These requirements are met without impairing its function o f providing reliable essential electrical supplies. Engines, generators and auxiliary equipment are, as far as possible, of standard design of proven reliability tp er a period of 20 000 running hours and preferably in service on similar duties. Diesel generators and their auxiliary equipment are designed for the following ambient conditions: Outside Maximum ambient temperature Minimum ambient temperature Relative humidity
40 ° C -25 ° C 100°7o
generators
Because of its installation in a nuclear power station, the equipment is suitable for a radiation dose of 0.1 mrad/h. The plant is normally designed for an operating life of 30 years under the conditions of operation described. Certain items of plant such as seals, gaskets and joints, cannot be obtained to achieve this life. It is therefore important that the manufacturer declares the presence of such components and their difficulties. In such instances facilities for easy access and rapid replacement are usually provided. Because of the generally high noise levels originating from diesel generators, stringent requirements are observed with respect to sound reduction by appropriate design of the diesel house, to ensure that noise levels in the neighbourhood are kept within reasonable limits so as not to cause annoyance to the public. These are set out in CEGB Standard 989907 — Noise Limits for New Power Stations. In addition, air intakes, exhausts and other secondary sources of noise external to the diesel house, e.g., fans, require special treatment to comply with the specified maximum permissible noise levels. 5.1.4 Protection against external hazards
High winds The diesel generator system is designed to withstand the effects of high winds. Adequate supports and re-
straints are provided for those items subject to high winds. The diesel house is designed to withstand the effects and therefore only plant items external to the building are considered, e.g., exhaust stacks, outdoor mounted cooler, etc. Three external hazards are guarded against: (a) High wind damage — maximum gust of 69 m/s for 3 s. (b) Windborne missiles, generally considered as a section of corrugated aluminium cladding from an adjacent building, measuring 6m x I mx 1.6 mm travelling at 50 m/s. (c) Windborne combinations of seaspray, rain and
snow.
!aside the diesel house maximum ambient temperature minimum ambient temperature Relative humidity
55 ° C – 10 ° C 100%
The design provides that the engines will run despite the effects of these hazards, in particular: • The starting system must remain functional.
Inside the local control room
Maximum ambient temperature Minimum ambient temperature Relative humidity
• The fuel supply system must remain functional. °
40 C – 10 ° C 85%
Where diesel generator systems are installed in close Proximity to the sea, due regard is given to corrosion Problems arising from the salt-laden atmosphere.
• The air intake must allow full-load running of the engines at all times. • The atmospheric coolers must remain intact and functional. • The exhaust must remain functional, i.e., unblocked, although not necessarily intact. 777
Emergency supply equipment The starting and fuel supply systems are totally protected against damage from windborne cladding. The air intake system allows the air flow required for full power running despite damage by the windborne cladding and possible blockage by windborne debris. It is capable of removing excessive windborne seaspray, rain and/or snow such that operation of the engine itself is protected. it is also capable of withstanding the strongest wind gust without significant loss of efficacy. Atmospheric coolers can withstand the greatest wind gust without damage and are protected against significant damage caused by windborne cladding. They are also protected against loss of efficiency due to blockage by winclborne debris or snow. The exhaust system and silencer are not required to survive the hazards intact but are designed always to provide a free passage for exhaust gases, bearing in mind possible damage caused by high wind or windborne cladding. These design criteria ensure that the plant remains running without significant loss of efficiency.
Seismic requirements Diesel generators are designed to operate after an earthquake in order to provide supplies to safely shut down nuclear reactors within the station. The magnitude of seismic vibrations can vary from station to station and also from one floor level to another within a building. To enable the manufacturer to design equipment to withstand seismic vibrations in combination with normal operational forces, the necessary details to calculate acceleration forces are given in the appropriate specification for a station. Diesel generator systems are designed to withstand twice the response accelerations which are calculated from the acceleration forces in combination with horizontal and vertical floor response spectra for the particular building. The ability of the equipment to withstand seismic vibration is established preferably by analytical methods, or by a combination of analysis and low level induced vibration tests. Where these methods cannot be used with confidence, items comprising the first production unit are subjected to shaker table tests. The equipment is energised during these tests and, where practical, it is at normal operating temperature. Monitoring equipment is used to evaluate the performance of the equipment before, during and after these tests. Full paticulars of seismic qualification procedure are contained in the CEGB Technical Specification and Schedules for Seismic Qualification of Electrical Plant (E/TSS/EX32000).
Avoidance of common mode failure In order to avoid common mode failure, the CEGB always reserves the right to obtain some of the machines for a particular station from each of two dif-
778
Chapter 9
ferent diesel engine manufacturers. This subject is giv en
careful consideration during the tender stage, w i t h particular respect to the tenderer,' information o n proven standard design and reliability and servic e experience on similar duties.
Location of diesel generators Diesel generators are usually located in engine room s in pairs, with careful attention to ensuring that failure of a component or system does not render both diesel generators inoperable (see Fig 9.7). In particular, where common systems are employed, standby plant and sufficient pipework and valving is provided to ensure that alternative supply routes are available for each diesel generator. Individual services to each diesel generator are separated but, where it is necessary to run syste ms in close proximity, then adequate protection is provided to each system to prevent common failure.
Fire protection The whole installation is designed to minimise both the risk and the effects of fire. Nevertheless, accidents can occur and the diesel generator installation, with
the exception of the bulk fuel storage tanks (see belco.%), is therefore protected against fire by an automatic system of high velocity watersprays. It is a design requirement that the operation of the fire protection system does not adversely affect the operation of a diesel generator running at the time of operation of the watersprays. Careful attention to waterproofing of equipment is therefore essential. Whilst individual certification of equipment for this condition is not required, a site test on the completed installation will subject the running diesel generator to high velocity watersprays, when any waterproofing deficiencies are made good. Any ancillary plant or electrical equipment likely to be affected by smoke, excessive heat or by the operation of the fire protection equipment is located outside the engine room in a separate plant room. The fuel oil bulk storage tanks are equipped to inject low-expansion foam as a fire extinguishing medium.
5.2 Engine and auxiliaries 5.2.1 Engine types and characteristics The engines specified by the CEGB are of the cold starting, compression ignition (diesel) type, pressure charged, operating on a four stroke cycle. The cylinder configuration is usually a 'vee' arrangement and, to obtain long life, the running speed does not usually exceed 750 r/min. In general, they comply with BS5514 and are suitable for use with BS2869 Class A fuel oils over the full range of engine operating conditions and ambient temperatures. A block diagram of a typical diesel generator system is shown in Fig 9.8.
Diesel generators
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i.1 6. 9.7 Side elevation of a diesel house, showing the location of diesel generator and its auxiliaries
5.2.2 Engine design and construction ,
:;:me assembly
I
IL eniline crankcase and frame are designed to be \!reineip robust and rigid constructions, with a prefor high grade castings rather than a fabricated Wlicre the latter is employed, careful . ,.! en:ion is paid io the manufacturer's construction, and inspection procedures, with particular quallty of welding (see Figs 9.7 and 9.9). \ thc engines spend long periods in the stationcondition, the manufacturer is required to give n.irtieular attention to the tensile stresses induced in iron components to reduce the risk of long term ,recp damage to the engine structure. The CEGB ..quires such tensile stresses not to exceed approxiiyly 25N of the material yield strength with the stationary. Allowance is made for the effects ■ katerside corrosion, which reduces material .1 kri s during the life of the plant. the crankshaft bearing housings can form part of hedplate or crankcase. Shell type, lined, high fatigue main bearings are used. They are split and ranged so that both halves may be removed without .
ic
disturbing the crankshaft. Any thrust bearings that require periodical adjustment are arranged to facilitate this operation. The crankshaft is a one-piece alloy steel forging, fully machined incorporating oil ways and an integral driving flange at one end. The whole of the rotating and reciprocating masses is balanced. All bearings, pistons, connecting rods, cam shafts, crankshaft, etc., are accurately machined to standard sizes. The aim is to ensure complete interchangeability of components throughout the engines of a particular size for a particular station and, whenever possible, on a national basis, thus reducing the cost of spares holdings. Cylinder blocks are provided with renewable cylinder liners which are separately cooled to minimise thermal stresses induced by the rapid start requirements. Liners are fitted with seals to prevent the interleakage of oil, water or gases within the engine. Means of detecting failure of the liner lower seals are provided. Each cylinder is provided with its own individual cast iron cylinder head, complete with starting air inlet valve, aspiration air inlet valves, exhaust valves, pres779
PP' Emergency supply equipment
HAND CONTROL
Chapter 9
ENGINE SPEED CONTROL
EARRING GEAR
CHARGE AIR iNDUCTION AND EXHAUST SYSTEM
NEUTRAL EARTHING RESISTOR
DIESEL ENGINE
STARTING AIR SYSTEM
PNEUMATIC CONTROL SYSTEM
ELECTRONIC GOVERNOR
LOCAL CONTROL PANEL
FUEL SYS TE M
PRESSURE & TEMPERATURE MONITORING
3 3kV
3 3kv AUXILIARY BOARD
GENERATOR
COOLING WATER SYSTEM
LUB OIL SYSTEM
ESSENTIAL Aux. BOARDS
EXCITER & PERMANENT MAGNET GENERATOR
AVR
ii
DIESEL CONTROL DESK
CENTRAL CONTROL ROOM
RADIATOR FANS
POST r i p SEQUENCE
EQUIPME NT
FIG. 9.8 Block diagram of a typical diesel generator system
sure relief valve, indicator cock and centrally located fuel injector. The heads have a high resistance to thermal stresses and are separately cooled to meet the fast response requirements. Heads are totally enclosed by individual covers except for the injector, which is located outside to avoid contamination of the lubricating oil by the fuel oil. To facilitate maintenance access, the crankcase is provided with inspection doors on both sides of the engine and is vented to atmosphere. Altogether, the whole engine is arranged to allow easy and rapid maintenance with a minimum of special tools. To satisfy statutory and personnel safety requirements, pressure relief valves and flame traps are fitted. The engine is cooled by a water cooling system, as detailed in Section 5.2.4 of this chapter. Lubrication
The CEGB gives preference to engines operating on a wet sump system and incorporating a forced lubricating oil system to provide correct lubrication under all operating conditions to all surfaces requiring an oil supply. The exceptions are the generator and exciter bearings which are separately lubricated (see Section 5.3.1 of this chapter). The lubricating oil capacity of the engine sump/ tank is sufficient for at least 24 h continuous operation of the engine at rated load without make-up. 780
Occasionally a manufacturer may put forward a dry sump design, but this must be demonstrated to be able to maintain a positive suction head on the lubricating oil pumps at all times. The main lubricating oil pump is of the positive displacement type directly driven off the engine. The pump takes oil from the wet sump via upstream coarse strainers. A standby electrically-driven pump, complete with automatic changeover controls and alarm initiating devices, is usually provided. The initiation of the electrically-driven standby pump is at a higher oil pressure than the 'low oil pressure' engine trip setting to permit continued engine running in the event of failure of the engine-driven pump. Oil coolers, using water as a cooling medium, are provided and are designed to avoid contamination of the lubricating oil by water due to leakage across the separate oil/water circuits. Interconnecting pipework is arranged for easy removal of the cooler end boxes for cleaning the cooler tubes. Thermostatic control is provided to regulate the system, safely maintaining the optimum oil temperature under all conditions of operation. Because the engine is stationary for long periods, it is essential to maintain the oil at the optimum tem perature for starting. This is achieved by fitting thermo statically controlled oil heaters (see Section 5.3.4 of this chapter).
JACK. 1 COOL IN(, WATEH. FIE1URN PIPE FUEL OIL BUS RAIL VALVE CAGE COOLING WATER SUPPLY AND RETURN PIPES
4 NDLICTLOH AIR CuCT
CHARGE AIR MANIFOLD
TURBOCHARGER
CYLINDER HEAD
EXHAUST DUCT
GENERATOR
CHARGE AIR COOLER
1
EMERGENCY STOP LEVER
STARTING AIR MANIFOLD INJECTION PUMP CONTROL ROD FUEL OIL INJECTION PUMP
esti lit41 1.4.4.1,11-10
LUBRICATING OIL EXTERNAL CONNECTIONS
0 ' ,
O fe-Ng dols . —JAN '44
IP
i
----
CHARGE AIR COOLER COOLING WATER PIPES
PNEUMATICALLY OPERATED AIR START VALVES
FIG. 9.9 General arrangement of a diesel generator unit
SECONDARY COOLING WATER ENGINE DRIVEN PUMP INLE f ISOLATING VALVE
sioleaeue5 iesa!G
LUBRICATING OIL RETURN FROM GENERATOR BEARING
111 m
Emergency supply equipment Duplicate full-flow fine filters, with replaceable elements and onload changeover facilities, are provided. Drip trays are fitted in this area and in all other positions of possible oil spillage. A dirty lubrication oil collection system is provided in each diesel house to cover each pair of engines. The tank is sized to contain the sump oil of two engines. Drainage of the sump to the tank is by means of a portable pump and flexible hoses. The tank is arranged for discharge to a road tanker. En addition, drainage points are provided at he lowest points of oil filters, heaters, coolers, etc. I are arranged to keep oil spillage to a minimum and all pipework is self-draining. Magnetic drain plugs are fitted to trap any metallic particles in the lubricating oil. A portable lubricating oil centrifuge is provided to service any of the diesel generators in a station and is sized to give a minimum of three changes per 24 h per engine. To facilitate this arrangement, using hoses, the necessary connections and valves are provided on each engine. It will be noted from the above that any draining or centrifuging of the oil involves the use of hoses. This requires a deliberate action on the part of maintenance personnel connecting the two ends of a hose and avoids the accidental opening of a valve on a fixed pipework drainage system which could cause an inadvertent loss of oil endangering the engine and jeopardising its availability. Compression fittings for pipe joints have given trouble in the past because of possible poor workmanship during assembly. They are reduced to a minimum nowadays and preferably not used at all in positions 1 m or less from the engine, to avoid the fire risk caused by oil spraying onto a hot engine.
Lubricating oil priming When the engine is stationary, oil will drain from bearings and cylinder liners. This is avoided by supplying these items with oil during stationary periods, either on a continuous basis or intermittently, controlled by a timer; this operation is known as priming. To safeguard the engine, duplicate (duty and standby) electrically-driven pumps are fitted for each engine, arranged so that in the event of pump failure the standby pump will take over the duty. An air-driven priming pump is also provided, which comes into operation if the electric pumps are unavailable. The priming system is designed to avoid lubricating oil entering the cylinder combustion chamber or exhaust system but, at the same time, cylinder liners receive adequate lubricating oil to prevent pistons sliding on dry walls on start-up. The priming pumps are capable of supplying sufficient oil to the bearings to enable the machine to be barred and also to allow the machine to be safely brought to rest should the main oil pumps fail when starting or running. 782
Chapter 9
Fuel injection Fuel injectors, fuel injection pumps (one per cyli n d er) and fuel filtration equipment are usually of the manu. facturer's standard type, thoroughly proven in servic e elsewhere under similar operating conditions. Adequate redundancy is provided in the operating drive and metering control to ensure the engine is not made u n . serviceable by individual component failure. Fuel injectors, incorporating filters, atomise the f ue l sufficient for complete combustion. The injectors are easily removable for maintenance purposes, for wh ic h a maintenance jig (including a test pump), are provid e d . The fuel injector pumps are individually cam-op_ erated, of the spring-return plunger type and are driv en off a common camshaft. They have means of ensuring equal distribution and metering of the fuel to all cylinders under all conditions of loading. Each pump is capable of being manually primed. The fuel system is self-venting and any fuel spill from the injectors is returned directly to the fuel oil bulk storage tank. Fuel pipes from the pumps to the injectors are sheathed such that any leakage is piped to a tank with a level alarm. Dual full-flow fine filters are provided upstream of the fuel injector pumps.
Flywheel Dependent on the inertia of the total diesel engine/ generator assembly, a flywheel is sometimes provided to overcome the cyclic variation in torque of a diesel engine. It is manufactured from a material free from significant defects and is subjected to an overspeed test at 150% normal engine running speed. The dynamic system, comprising engine and driven machinery, is so designed that critical speed vibration stresses do not exceed the recommended values given in the latest edition of Guidance Notes of Lloyd's Register of Shipping.
Barring gear Motor operated barring is provided to turn over the engine at slow speed at regular intervals in conjunction with the priming equipment described above, during long periods of idleness and for maintenance purposes. Interlocks are fitted to prevent engine operation with the barring gear engaged. Provision is also made for manual operation. The electrically-driven gear is made inoperative when hand operation is in use and starting of the engine is prevented with hand barring gear engaged. Barring gear 'engaged' indication is provided at the control panels. Facilities are available for 'inching' the diesel gen erator rotors to enable them to be positioned angularly with precision for purposes of erection and maintenance (see also Section 5.3.4 of this chapter). The drive motor of the electrically-powered barring gear is designed to turn the diesel generator from rest.
Diesel generators Ix automatic decompression device is sometimes used ee the standstill torque required from the motor. rcii ii
Hu
/a/croo
ns
r or engine and generator to be mounted bedplate to provide a rigid assembly. be foundations are provided by the civil 01,,, h [ emploed by the CEGB, the diesel generator r provides the basic design of foundations Lifacture LI fC1 his equipment. This should withstand the [e hazards previously referred to in Section 5.1.4 • chapter. It should also ensure, as far as pos, murn isolation of the building structure from \i , Hinied vibrations when the plant is operational. 5 2.3 Starting equipment enerators are started by supplying compressed he cylinders (Fig 9.10). For this purpose, a cornair sLarting system with automatic and manual s%stems is provided for each engine, together h a common charging section feeding the separate ,!.,:Lne systems. This common section comprises two .',... mcally-driven compressors on a duty/standby sys•,!],. each capable of being selected to duty. They sup, pipework ring main from which the individual , inc ystems are fed. In order to regulate the rate pr ure change and to act as an accumulator, a -,...eo,er is fitted to the common system. I .teh engine system consists of two air receivers • ,Hitomaie starting and one air receiver for manual g
starting, all being fed individually from the common system ring main. The automatic systems operate simultaneously on separate banks of cylinders of the engine. Each system is capable of starting the engine in the event of failure of the other system. Independent pipework is provided from each starting receiver to the starting valves of the engine. For each automatic starting system, duplicate sole0 noid-operated start valves, each rated for l00 ra air flow requirements for the whole engine, are provided for each cylinder bank. The start valves are arranged for parallel operation both electrically and pneumatically. Manual isolating valves are fitted on either side of each of the solenoid valves. These permit each one to be taken out of service for maintenance without affecting the others and without reducing the starting ability of the engine. A manually operated valve is provided for the manual start system. Each engine system also incorporates a separate air receiver for the air-driven lubrication priming pump described in the previous subsection. This receiver is separately supplied with its own pipework and valves from the common charging ring main. The capacity of each of the individual engine starting system air receivers is designed to achieve six starts without recharging from the common air system. This ensures ample capacity in the event of failure to start the engine on the first or subsequent attempts. Similarly, the capacity of the air-driven lubrication priming pump air receiver is sized to provide sufficient
SET FUEL CONTROLS FOR START
ELECTRICAL SIGNALS FROMPTSE ccia OR CONTROL DESK SOLENOID OPERATED AIL AIR START VALVES A BANK
MANUAL START ArR PrECEr - :ER
V A -
.K.JTO START AIR Er.:;EIVER If
ELECTRICAL SIGNALS FROM POST TRIP SEQUENCE EQUIPMENT — CENTRAL CONTROL ROOM OR CONTROL DESK
CONTROL AIR LOCAL PANEL START PUSHBUTTON
TO
ENGINE CYLINDERS PNEUMATICALLY - OPERATED AIR START VALVES B BANK
' SOLENOID I VALVES SET FUEL CONTROLS FOR START
FIG 9. LO Enume start system
783
Emergency supply equipment
Chapte r 9
air for about 2.5 minutes of running which is considered sufficient to provide adequate lubrication prior to the first start attempt. Air compressors and drives
Each compressor is of the air cooled type, mounted on a common bedp1ate with its electric motor and associated equipment to make a complete packaged unit for floor mounting (Fig 9.11). It is aligned in the manufacturer's works for easy erection on prepared foundations designed to the requirements of the manufacturer. Emphasis is again placed on a standard design and construction of proven reliability. Equipment associated with each compressor comprises air suction filter, silencer, intercooler, relief valves, automatic start and stop features in the form of pressure switches, automatic unloading gear and automatic drain valves. Means are also provided for separating oil and moisture from the compressed air. Each compressor is capable of charging the two largest receivers from atmospheric pressure to normal working pressure in the minimum time commensurate with the requirement that the compressor is kept running for a period of about 20 minutes under normal charging conditions. This period is chosen to enable the compressor to reach its normal working temperature and reduce wear and tear due to frequent stops and starts. Whilst it is generally left to the manufacturer to specify the above times, in no circumstances is the recharging time allowed to exceed one hour. Air receivers
Each receiver is fitted with a relief valve, non-return valve, drain connection and valve, moisture trap, pres-
sure gauge, a pressure operated alarm switch (receiv er low pressure) and facilities for regular statutory inspections. The receivers and fittings are manufac. tured and tested in accordance with 3S1123 and BS5169. The relief valves are piped to a safe discharge poi nt to avoid danger to personnel. For maintenance pu r . poses, the air supply pipework to the receiver inco r . porates an isolating valve. To prevent corrosion, the internal surfaces of air receivers are either galvanised or coated with a flame resistantcoating approved by the CEGB. Air pipework and valves
Pipelines are sized to allow the required air quantities to flow without prejudicial pressure drop and they in. corporate drainage slopes. Pipework and valves are designed to withstand a hydraulic pressure of twice the working pressure (Fig 9.12). Manually operated isolating valves are provided in the diesel generator room to isolate the starting air system from the diesel engine whilst work is being carried out on the engine. The valves have padlocking facilities to enable them to be locked off in compliance with the CEGB Safety Rules. Similar isolating valves are provided for all other pneumatically operated auxiliaries associated with each diesel generator. The manual isolating valves are also interlocked with the barring gear to prevent it from being engaged until the isolating valve is in the closed position. Internal surfaces of pipework are coated, similar to the interior surfaces of air receivers. For small bore pipework coating is not possible, arid this is usually supplied in stainless steel to BS3605.
PUTT CV .. PLI- ER 5ILENCER
DRAIN BOTTLE DISCHARGE
FIG. 9.11 784
General arrangement of air compressors
Diesel generators
•-=
HUFFER AIR
RECEIVER
-
y-
co r,1 PR ES SC. RS
c..:.- PRESSCRS
i>1
D
A
11",
•
110
•
•
7
V AIR AX' RE:Ei,ERS X ENGINE A BANK AUTO
Ax X ENGINE 'v1 ANUAL
START
START
FIG.
AX2
LO AX
LO AY
AY2
.AY
AY1
X ENGINE B BANK AUTO START
X ENGINE LUB OIL PUMP
Y ENGINE LUB OIL PUMP
Y ENGINE A BANK AUTO START
Y ENGINE
V ENGINE B BANK AUTO START
9.12 Compressed air ring main system
where vibration can become a problem, e.g., in cinity of compressors, flexible pipework is pro\ kleLl to avoid fatigue fracture and noise transmission. 5.2.4 Cooling system diesel generator is provided with a radiator system
(I
MANUAL START
9.13) with separate circuits for cooling of:
• Pie engine jacket water. • The secondary water system, supplying coolers for
engine lubricating oil, charge air system, generator coolers, etc. !• ach radiator system is complete with its own water
;n.ike-up tank, radiator, electrically-driven fans, filters,
niPework and valves. Pipework is arranged to conrleci separate sections of the radiator to the jacket and 'cLondary cooling circuits and valved to enable one ...] ftuit to be taken out of commission without affecting th,: others. There is no interconnection between cooling
circuits, with the exception of the common make-up supply. To maintain the optimum engine working temperature under all conditions of operation, the engine jacket cooling water circuit is thermostatically controlled. This includes keeping the engines in a suitable pre-start condition, which may need the use of off-load heaters (see Section 5,3.4 of this chapter). To prevent air locks, continuous or automatic venting from the high parts of the water system is provided. The engine jacket cooling system is arranged to feed water direct from the engine to the radiator, with circulation maintained by an engine-driven water pump. It is also usual to provide a standby electrically-driven pump with automatic start facilities in the event of failure of the engine-driven pump. The separate secondary water system, for the other coolers mentioned above, feeds water direct to a separate section of the radiator with circulation maintained by a separate engine-driven water pump and a 785
VP"' Emergency supply equipment
Chapt er 9
MAKE-UP TANK
Tr
RADIATORS
ROEPS
PUMP
CC>
JACKET WATER --1
4
ALTERNATOR AIR COOLER
-1 1CHARGE AIR
ENGINE DRIVEN PUMP
COOLERS I 1—
LUB OIL COOLER
—
SECONDARY WATER
H
COOLER He.-
HEADER TANK
VALVE
CAGES
VALVE CAGE WATER
FIG. 9.13
Block diagram of a cooling water system
standby electrically-driven pump, similar to the one already described. A flow indicator is provided on all engine circulating water discharges. Comprehensive precautions are taken against freezing of any part of the cooling system by including off-load heaters, antifreeze solution and trace heating. Also, where necessary, lagging is provided.
and out to prevent corrosion. They are of the closed (fully covered) design, vented to atmosphere and sized to ensure that no overflow occurs due to expansion of the coolant at any operating temperature. They are fitted with a calibrated level indicator visible from ground level. Tanks are erected on steelwork at a height which provides a gravity feed to the radiator systems. Personnel access platforms are fitted for cleaning.
Water make-up tank Tanks are constructed generally in accordance with BS4I7 Part 2 from mild steel and galvanised inside
Radiator and cooling fans A radiator with fan assemblies is provided for each diesel generator unit (Fig 9.14). The assembly forms
786
Diesel generators
E_EYE',7
;ACKE
aurn_ET
ROTOR
GEARBOX ELECTRC MOTOR UNIT
FIG. 9.14
Cooling water radiator and fan
neural, self-contained, free-standing unit and is ormally mounted on the roof of the diesel generator with maximum efficiency of heat transfer to :iio , phere. Radiators are constructed from a number (. parate cooler elements, any one of which is capable iq being removed without disturbing the others, inihe provision of isolating and drain valves for element. The elements are constructed from non•.rrous materials in separate sections to accommodate :ne , eparate cooling circuits. A number of elements can he iked on any cooling circuit, but the use of one ...1,:inent on two separate cooling circuits by division of he header is avoided. rwo nominal 100% duty, thermostatically controlled 7,1,1E xur cooling fan groups are provided, so that each !,111 group on its own can provide 100% diesel gencooling at an ambient temperature of 15 ° C. i he Ian groups are arranged on a duty/standby basis, li h either group being capable of selection as the duty 111 group. The second fan group is arranged to act atomatically as standby in case of failure of the duty roup and to supplement the supply of cooling air dur,
,
:2
ing periods of ambient temperature in excess of 15°C. The fans are electrically-driven with a preference for direct drive. Multi 'vee' belt drives are acceptable, so long as twice the number of belts required for the duty is provided, together with belt adjustment and motor/fan alignment facilities.
Water pipework and valves All interconnecting pipework and valves are designed and installed in accordance with CEGB Standard 239903 — Piping Systems — Low Pressure Water Services'. Compression type pipe couplings are not used where failure could result in a safety hazard to personnel or plant. Where necessary, expansion joints are fitted, e.g., on long runs. Provision for drainage and collection of the water is also provided. 5.2.5 Fuel oil systems
Each diesel generator fuel oil system basically comprises bulk storage tanks, transfer pumps, daily service tanks, line filters, recovery tanks, etc. 787
1 Emergency supply equipment The capacity of the bulk storage tanks is calculated to provide a minimum of 80 hours full-load running of the associated diesel generator. The daily service tanks are sized for 8 hours fullload running. A eravity fuel supply to the engine from the daily service tank is preferred for all states of diesel generator loading, to avoid the use of additional auxiliary equipment ,‘Iiich could jeopardise the fuel supply to the engine under emergency conditions. At some installations this cannot be achieved and, in these instances, duplicate pressurising pumps (engine-driven and electrically-driven standby) are provided. In any circumstances, the diesel generator must be capable of a black start with at least 10% of rated output by gravity fuel feed, with the pressurising pumps by-passed if necessary. To enable each daily service tank to be replenished automatically from the bulk storage tanks, duplicate fuel oil transfer pumps are provided and operate on a duty/standby basis. These are of sufficient capacity to make up the fuel used from the daily service tank by running for not more than half of the engine running time. A deadweight type fire valve with fusible link is provided to drain the daily service tank to the bulk storage tank automatically in the event of a fire. Operation of the fire protection system will inhibit operation of the transfer pump to the tank concerned. The fuel oil is arranged to reach the engine at the correct temperature for atomisation, irrespective of ambient temperature. Where necessary, thermostatically controlled fuel oil heaters are installed to achieve this. Daily service tank and associated equipment
Tanks are constructed in accordance with BS799 Part 5, using mild steel coated with an oil resistant treatment, approved by CEGB. They are vented to atmosphere via a flame trap. An overflow is provided with pipework back to the recovery tank. An easily cleanable sludge trap is fitted. Because of the height at which these tanks are likely to be mounted, ready access for cleaning in the form of galleries and ladders is provided. A calibrated level indicator, visible from ground level, is provided.
Chapter 9 A tank level indicator and local high level visual and audible alarms are provided. A temperature monitor in the gas space above the fuel oil level provides a high temperature alarm for fire prevention. Because the tank is located in a pit, permanent galleries and ladders are provided for cleaning and for access to valves and the sludge trap (see Section 5.1.4 of this chapter for fire protection).
Recovery system
in order to collect fuel oil leakage, blowclown, etc,, from the engines and overflow from the daily servi ce tank, a recovery system is provided including a recovery tank. From the latter, oil is automatically returned to the bulk storage tank. Dependent on the relative heights of recovery tank and bulk storage tank, automatic duty/standby electrically-driven pumps are sometimes fitted to return the oil to the bulk storage tank. A visual level indicator is fitted. The construction of the recovery tank is generally si milar to that of the daily service tank. Oil pipework and valves
All interconnecting pipework and valves are designed and installed in accordance with CEGB Standard 23992 — 'Piping Systems — Oil Services'. Pipework is not routed over the engine exhaust manifolds or in any position where it is at risk from fire in the event of leakage from pipe joints, etc. Provision for drainage by suitable trays and pipework is provided. Compression type couplings are not used where their failure constitutes a fire risk or a hazard to personnel or plant. Adequate supports and flexible pipework are used to minimise the dangers of pipeline fatigue fractures due to vibration. Immediately after testing, the fuel oil system is treated with an inhibitor to ensure that the fuel lines are protected from rust, corrosion, scaling or any form of deterioration. 5.2.6 Inlet and exhaust air pipework, turbochargers and silencers Aspiration
Bulk storage tanks
The tanks are constructed in accordance with CEGB Standard 20752 — 'Fuel Oil Storage Tanks' and BS2594. They are located in pits in the diesel house. After manufacture, they are given an oil resistant treatment approved by the CEGB. Additional capacity is provided in the bulk storage tank above the normal high level control which stops the transfer pump, to accommodate the contents of the recovery tank and the daily service tank when emptied by the operation of the fire protection. 788
The aspiration system draws air from outside the engine room via duplicate filters with an air inlet designed such that 100% air flow to the engine at the design pressure drop can be achieved with one filter panel blocked or removed for cleaning. The design of the intake and the air approach velocity are arranged to avoid the ingress of moisture from any source as well as the draw-in of snow. The CEGB usually prefers engines with exhaust driven turbochargers to supply air for complete fuel combustion at maximum loading to achieve the full
Diesel generators j rating of the engine. The turbochargers are readily easily dismantled for maintenance and and They have a separate lubricating oil system ,; with means of checking oil level. ur i cr air is usually intercooled. Air-to-water charge 00lets are provided with the intercooler forming ,. part of the engine cooling circuit. . premature failures due to fati ,, tte, ductpported and free of vibration while the fully su is running by the fitting of flexible joints. for engine inlet air temperature measurelitiCS e provided. ar
,hdast manifold Die engine has a smooth flow gas exhaust manifold ia the turbocharger to the exhaust system. ,our i e d v rder to avoid injury to personnel, the exhaust o is shielded to give a maximum surface ternld ° of 65 C under all operating conditions.
:cnLers and exhaust pipework design of the exhaust system ensures that the back on the engine and the noise level are kept as as practical. Provision is made for spark arresting r:2Lluee the fire danger. Lileneers are manufactured from heavy gauge sheet cl and all internals are secured by continuous weldTo release any condensed moisture, drain plugs are , -oided. The outlet of the silencer is terminated at a ;r ■%hich allows adequate dispersal of exhaust gases. Me exhaust pipework is usually flanged heavy gauge tubing to BS806 Class B, with expansion joints 7 0 ensure that no stresses are imposed by expansion the building structure from which the pipework is , ipported. Weather and heat shielding is provided for silencers .1TIJ exhaust pipework external to the building. All pipework internal to the building is lagged clad with aluminium sheet to prevent excessive •,:ruperature in the building. Lagging and cladding is . ,.1 ,,l ays arranged for easy removal for maintenance, .here this is required. \s for the exhaust manifold, heat shielding is ap; , lied to all parts of the system within 3 m of ground el or which are accessible from personnel access points. , Due to the exposed nature of certain seaside power idtions, care is taken to ensure that cladding external the building will shed water and withstand high "Ith-ls, as defined in Section 5.1.4 of this chapter. For reason, to give additional protection, all items posed to the open air are sprayed with metallic ,Aliuminium and immediately sealed by two wet coats iilicon aluminium sealer capable of withstanding operating temperatures up to 450 ° C. 5.2.7 Governors
Eak:h engine is provided with a main governor of the
electronic type and a standby mechanical governor. The engine governing limits specified are to BS5514 Class Al. The governor system provided, permits the engine speed to be varied from 80% normal speed at no-load to 2Tio overspeed at full-load. Means are provided for this speed adjustment to be made by hand from the station central control room, at the local engine control panel and at the engine itself. The governors regulate the quantity of fuel oil supplied by positioning the fuel pump control racks to suit the load demand. On failure of the electronic governor, facilities are provided to ensure changeover to the mechanical governor.
Electronic governor This governor operates from either the 110 V, single phase 50 Hz, guaranteed essential instrument supply available in a power station (uninterruptable power supply) or a 110 V DC supply obtained from batteries. It is capable of maintaining the generated frequene!, between 48 Hz and 51 Hz under normal operating conditions. Remote control of speed is provided, when running in parallel with the system, as described in Section 5.1.2 of this chapter. This control permits operation of the engine at any load at frequencies between 48-51 Hz. For parallel running with the system, speed droop is switched in. To permit running when isolated from the system (if required for emergency duty), speed droop is switched out. The governor reponse rates are designed to enable it to cope with block load applications and rejections of 25%, 50 07o and maximum load, together with the worst loading sequence specified for the particular station under emergency duty conditions. In the event of failure of the electronic governor, an alarm is given with the engine either running or stationary. Mechanical governor This governor is of the centrifugal type. It has a speed setting of about 5 (ro above that of the electronic governor to avoid interference. When the speed reaches the level of the mechanical governor, it will assume and maintain control of the engine. It is provided with a fixed speed droop such that, at full-load, the engine on mechanical governor would run at its rated speed. Overspeed trip device A separate overspeed trip device is provided to operate in addition to (and independently of) both electronic and mechanical governors, to protect against runaway or damage to the engine with possible risk to personnel should both governors and their associated fuel controls fait. 789
Emergency supply equipment
Chapter 9
The overspeed trip device is separately driven off the camshaft gear train. It operates independently of the fuel pump control rack, by actuating the fuel pump blowdown system, which clears the fuel and air locks the pumps. The setting of the overspeed trip is arranged so that a temporary rise in speed due to instantaneous loss of full load, when operating with either governor setting, w ill not cause a trip condition.
5.3 Generator and electrical equipment 5.3.1 Generator design and construction
Reliability being a prime requirement, manufacturer's standard units are preferred which can be demonstrated to have a proven record of reliability. At times, it is preferable to install a standard unit, even if it does not fully comply with every detail of the specification, so long as these departures are identified at the tender stage. The generator unit is designed to comply with BS5000 Part 99 and BS4999 Parts 3 and 51. The type of environmental protection provided, i.e., to BS4999 Part 20, IPW55, enables the machine to operate satisfactorily under fire protection deluge conditions (see Section 5.1.4 of this chapter). The method of cooling preferred by the CEGB is that covered by BS4999, Part 21, 1C31, utilising a fan mounted on the generator shaft. This avoids reliance on separately driven auxiliaries such as fans and pumps. Cooling air is taken from and returned to the outside of the diesel generator house via inlet air filters and outlet air protective louvres. For very large machines the above method of cooling may be inadequate. Under these conditions, a forced air, water cooled design to IC81 may have to be accepted, so long as the constructional requirements comply with ESI Standard 44-3 — 'Electric Motors Specification (3300 V and above)'. Insulation is specified to comply with BS2757 Class F. However, to achieve a long insulation life, temperature rises are limited to the lower Class B temperature. Since the generator unit is required to operate suddenly after long periods at standstill, off-load heaters for anti-condensation protection, anti corrosion protection, and the protection of bearings against transmitted vibration are provided. The . generator unit is capable of continuously withstanding levels of imposed vibration from the engine of 0.25 mm peak-to-peak amplitude between 5 and 10 Hz and levels of imposed vibration velocity from the generator core in accordance with BS4675, Classification 11.2, between 10 and 200 Hz. These levels can be measured at any point of the frames or bearing pedestal. -
Generator mechanical design Generators are salient pole machines, with a revolving 790
field of the brushless variety, i.e., with shaft-mounted diodes as rectifiers for the provision of DC excitatio n current. The machirws are suitable for direct couplin g to the diesel engine and have their own self-lubricated bearings in accordance with ESI Standard -14-3, Sec. tion 5.4.1. The generators may share one bearing with the diesel engine. The bearings are split horizontally for ease of maintenance. The rotor shaft is a single forging, machined all me r with an integral coupling flange. Because of the cycli c variation in the torque of a diesel engine, the rotor is capable of withstanding continuously a N. ibratory torque of +2.5 times the rated full-load torque over the range of 95 to 110% rated speed. It is also capable of withstanding +6 times rated full load torque when passing through critical speeds. Means are provided to prevent the circulation or shaft currents through the rotor and bearings by the use of an insulated bearing pedestal. On-site balancing facilities are provided. Generator electrical design The generator is capable of supplying, for one hour during any period of twelve consecutive hours' running, a load 10% greater than the nominal continuous rating. As stated previously in Section 5.1.2, the generators are not normally required to operate in parallel with each other, but must be capable of operating satis. factorily in parallel with the station electrical auxiliary system for the purpose of full load testing. Reactive kVA sharing equipment is therefore provided (see next Section 5.3.2). When operating in this mode, harmonic currents produced by the generator are circulated through the machine and other equipment. Such currents must be within the temperature rise capabilities of such equipment. The 3.3 kV stator windings are star-connected, with the neutral bar connected to earth via a resistance to li mit the phase to earth fault current to 1000 A, to minimise damage under fault conditions. Separate line and neutral terminal boxes mounted on opposite sides of the stator casing are usually provided, designed to limit damage to other plant and injury to personnel in the event of a through or internal fault. The length of the stator may at times prohibit the fitting of such boxes direct to the stator casing because of their size. In these circumstances, separate freestanding line and neutral terminal boxes are used. These are located adjacent to the stator and linked to it by means of connections in ducts. , If the stator is not solidly bolted to its foundations i.e., it is located on anti-vibration mountings, care is taken to incorporate the necessary flexibility into the cable connections to the terminal boxes, or to the ducted connections when separate free-standing terminal boxes are provided. Current transformers necessary for control and pro tection of the diesel generator are accommodated In -
Diesel generators
Jr 9 eo
ion
li ng it ed
+le neutral terminal box. For robustness, ring type • oot transformers are preferred to wound types. 't rmers are accommodated in the assooit,l e trans f o jrcuit-breaker equipment.
ith it I
5
Excitation equipment and automatic
voltage regulator (AVM
made in the first seven paragraphs of 5.3.1 of this chapter, also apply here.
k. er. -or Or ver bl e len
3.2
-1
cif th e
Air
prs it h ;isry ve
/
of the brushless variety, directly coupled to pipe-kentilated from the generator. The machine .:rot.iu,:es three-Phase AC power which is fed via conrunning along the shaft direct to the diodes cried to in the previous section. file exciter is capable of withstanding, for a specified of time, a short-circuit across the DC output - Hod ne,:tions to the generator rotating field and the loss n ne or more diodes. o \leans, in the form of a resistance switched across field, are provided for rapidly suppressing the field ,..:Trent during fault and shutdown conditions. rite exciter, diodes and excitation control equipment L:apable of operating at maximum (ceiling) voltage 'or at least 5 s, to cater for field forcing conditions, to . e system stability and to ensure rapid protection : , ri.erk ,Teration during system faults. Provision is made for diode bridge arm failure
tX
red /
es Ii
!id
rk(iration control and AYR Hie generator voltage is controlled within the limits of 13‘, 4999 Part 40 for voltage regulation grade VR2.3.1. to achieve this, the AVR is of the continuouslyag state thyristor type. One automatic channel .:i:J a manual control device, with suitable manual ..lanuover circuits and controls, are provided. Each .1,innel is capable of operating independently of the .! her. A null balance indicator is provided to allow manual transfer between automatic and mancontrol. in slew of the very high reliability of modern AVRs, He diesel generator is tripped in the rare event of an R failure. This is considered preferable to the .. , niplication of automatic follow-up by the manual ontrol device and automatic changeover to manual if he auto channel becomes faulty. As briefly mentioned in the previous section, ree kVA sharing equipment is provided. This is only 11 operation when running in parallel with the station LL'im. liary system and is removed from service autowhen the diesel generator receives an erner-"-Ttcy start signal. It is controlled by a selector switch li the station central control room, which also switches , governor droop in and out of service. 0 The AVR with its ancillary equipment is normally . Lated in the diesel generator local electrical cubicle. ,
le
5.3.3 Diesel generator control and protection equipment Control system
Under normal standby conditions, the diesel generators are not running but are left in a state of readiness for starting on demand. The control system for each diesel generator is designed on the following principles: • The control scheme for each machine is separately supplied and fused. • Loss of a single fuse, supply, or component or a single contact failure does not render inoperative the starting, running or control of a diesel generator. • The operating voltage of each control system is 110 V DC. Initiation of the automatically controlled starting sequence for each diesel generator is either automatic, by means of a signal derived from the reactor post-trip sequence equipment, or manual, by means of pushbuttons from either the station central control room or the diesel generator local control panel housed in the diesel generator building. The latter location is normally used only for testing purposes after maintenance work has .been carried out. A two-position selector switch is provided in the station central control room of a nuclear power station, having the following functions: Position I The diesel generator is available for automatic operation or for manually-initiated testing and loading from either the station central control room or the diesel generator local control panel. Position 2 The automatic override from the reactor post-trip sequence equipment is inhibited, leaving all other local and remote controls operational. For in-service operational testing and loading of a diesel generator, with the selector switch in position I, the sequence is as follows: • The operator initiates starting by using the appropriate pushbutton. • The diesel generator will run-up automatically and excite to 3.3 kV. • Synchronising to the 3.3 kV system is initiated, followed by loading. • After completion of the routine test, the diesel generator is manually taken off-load and shut down. For testing after maintenance work has been completed, with the selector switch in position 2, the sequence is as follows: 791
Emergency supply equipment
Chapter 9
• The operator manually initiates starting, run-up and excitation to 3.3 kV, using the appropriate facilities at the diesel generator local control panel.
rect relationship between various automatically con, trolled functions. They are sometimes known as 'sequence' interlocks.
• When the above sequence is complete, the speed and voltage controls available at the local panel or in the station central control room can be used prior to synchronising, with the 3.3 kV system.
• Essential interlocks — these are permanently i n service to protect individual items of plant. They generally trip the 415 V or 3.3 kV switchgear supply. ing the devices they protect. They are sometimes known as 'safety' interlocks.
• Nfter the operator has satisfied himself that the
diesel generator is ready for returning to emergency service, it is shut down manually and the selector switch is returned to position Manual and automatic synchronising facilities are available in the station central control room and at the local diesel generator control panel. Protection
The provision of initiating devices for automatically shutting down the diesel engine and tripping the diesel generator 3.3 kV circuit-breaker are restricted to those considered to be essential, bearing in mind the duty of the equipment and the requirement for high reliability. Wherever possible, the operator is given prior warning of an impending trip to enable him to rectify the fault before a trip occurs. A typical example is the lubricating oil temperature. Two temperature sensors are provided; the first and lower-set device provides an alarm only for high temperature and the second device operates on extremely-high temperature only to trip the diesel generator. The following is a typical list of protection trips: • Circulating current (generator stator phase faults and earth faults). • Extremely inverse overcurrent (back-up protection). • Excitation diode short-circuit. • Excitation overcurrent (time delayed trip). • Undervoltage (time delayed trip). • Overvoltage (time delayed trip).
A l arm system
Each diesel generator local control panel is equipp e d with alarm annunciator equipment to draw the Op_ erator's attention to fault or abnormal operation of the diesel generator unit and its auxiliary systems. This provides local visual and audible alarms for the safe and efficient operation of the plant. This alarm system is independent of the station service alarm system in the station central control room and self-contained in its operation. However, a limited number of important alarms are repeated to the control room. The remainder, i.e., alarms that require the control room staff to despatch an auxiliary plant a ■ tendant to the normally unmanned diesel generato, room to take the necessary remedial action, are grouped as repeat alarms to the control room. The alarm system obtains its electrical supply from the 1 . 10 V AC guaranteed essential instrument and control supply (uninterruptable supply). Emergency stop
Each diesel generator is provided with an emergency pushbutton switch mounted on the local electrical panel. The pushbutton switch operates into the engine shutdown system described above, including tripping of the 3.3 kV circuit-breaker. The pushbutton switch is of the 'stay put' type, i.e., after depressing, the contacts stay closed until the switch is reset by means of a key normally held by senior authorised personnel. This ensures that operation of the pushbutton switch is fully investigated by management before the diesel generator is returned to service.
• Jacket water temperature high. • Lubricating oil temperature high. • Lubricating oil temperature low. To shut down the engine, all protective devices act directly to shut-off the fuel supply to the engine by means of a solenoid valve. This is energised to shut-off the fuel and requires local manual resetting following operation. Interlocks
Interlocks are provided on each diesel generator to protect plant and personnel. They are grouped in two categories as follows: • Operational interlocks — those which operate in the automatic control equipment to maintain a cor792
5.3.4 Control of auxiliary systems Lubricating oil priming system
The priming pump automatic control system incorporates adjustable timing equipment to start and stop the duty priming pump, to achieve the engine manufacturer's recommended priming cycle. In some cases, priming is continuous and, if the duty pump fails, the ti ming equipment signals are automatically transferred to the standby pump. Total failure of the lubricating oil priming system is detected by a pressure switch, which initiates a local audible and visual alarm. This alarm is interrupted by the ti ming equipment when priming is not i n operation.Where intermittent lubricating oil priming is pro vided, it is interlocked with the diesel generator auto-
Diesel generators system such that, in the event of a t a te StaffLRg for the diesel generator to run during iblai'rement ngine start-up overrides the priming cycle. the e • rle lubr i ca ting, ) I priming system is also started %k hen the associated diesel engine is ice :o loss oi Oil pressure. The lubricating oil mps can also be started manually local to ra
,2 enciator. barring, as described in Section 5.2.2 of „t,iper, is controlled from a local control station H to the diesel generator. It is sometimes inwith the diesel generator local control panel. ' totlo \Ong control equipment is provided: s‘:,trz stop control switch for continuous barring in :]le forward direction only.
•
I or+ard.'reve.rse 'inching' pushbuttons for main-
•
!Lti,inee purposes. rical interlocks are provided to ensure that moI .,,ri,cd barring cannot commence until the drive is eneaged and an adequate supply of lubricating oil , resent. Failure of this oil supply during barring ; - ,lers the barring gear inoperative by tripping the 41 4 V supply to the motor. npressed air starting system ,tinpressor control equipment is provided for auto,. ontrol of the two air compressors described ;1 '.ection 5.2.3 of this chapter. This maintains the ..,.en,ers and ring main charging system at the required ; , :-e—ure by means of pressure switches, as follows: Fo start the duty electric motor driven compressor 'Ii
falling pressure.
It the duty compressor fails, to start the standby electrically-driven compresser on falling pressure
.i nd to initiate a local audible and visual alarm Jii air compressor fail'. This pressure switch is operate ii a pressure significantly lower than Ihe pressure s‘k !toll in (a) above. .1 II duty and Ntandby compressors fail, to initiate a local and visual alarm 'starting air pressure 10%s'. This pressure switch is set to operate at the iii.t_dier or I he two pressures detailed below, and signiticantly lower than the pressure switch in (b) above: • I he pressure corresponding to the minimum required tor the pneumatic devices associated with the diesel • ,
I tic minimum pressure required to provide the full i,irtine duty described in Section 5.2.3 of this chapter.
I:1e pressure switches are located so that one corn' or can can be taken out of service, leaving the control alarm system operative.
The compressor control equipment, including the duty/standby selector switch, is housed in a cubicle located in the engine room. This is constructed to withstand a deluge from the diesel generator fire protection system. Radiator cooling fans The duty group of radiator cooling fans, described in Section 5.2.4 of this chapter, is started at the same ti me as the diesel generator, whereas the starting of the standby group is initiated thermostatically on high cooling water temperature due either to failure of the duty group or high ambient temperature. A local
audible and visual alarm is initiated whenever the standby group is running. Alarm thermostats are provided in each section of the cooling system. They are set to operate at a temperature below the setting of any high water temperature trip of the diesel generator unit. Duty/standby selection of the fan groups is provided on the diesel generator local control panel. Auxiliary cooling water pumps Cooling water is normally circulated by the enginedriven cooling water pump. If it fails, the auxiliary electrically-driven cooling water pump is started thermostatically or on flow failure and, at the same time, a local audible and visual alarm is given. Fuel oil transfer pumps The duty/standby fuel oil transfer pumps are arranged to replenish the daily service tank automatically by drawing fuel oil from the bulk storage tank. The automatic control of the duty fuel oil transfer pump is initiated from a pair of magnetic level switches located within the associated daily service tank. One is designed to start the duty fuel oil transfer pump. Should this fail to start or fail whilst operating, the standby pump is automatically started from the same level switch. The second level switch gives a stop signal to both pumps when the tank has reached its full level. Separate level switches are provided in each tank for alarm purposes as follows: • One located at a higher fuel oil level in the tank than the pump stop control level. It is arranged to give a local audible and visual alarm when the tank is full and either of the pumps has failed to stop. Sufficient time is allowed for the operator to take the necessary action before fuel oil overflows back to the recovery tank. • One located at a level below the pump start control level and arranged to initiate a local audible and visual alarm when the quantity of fuel oil remaining in the tank is sufficient only for one hour running time of the associated diesel generator at full-load. Duty/standby selection of the pumps is provided on the diesel generator local panel. 793
Emergency supply equipment Lubricating oil and diesel engine water jacket heaters Where such heaters are provided for use during standstill periods of the diesel generator (see Sections 5.2.2 and 5.2.4 of this chapter), they are controlled by thermostats. Usually three thermostats are provided for each heater or group of heaters, i.e., control, safety (if the control thermostat fails to switch off the heater) and low temperature alarm (if the heater or its associated control thermostat fails).
5.4 Testing Throughout works, site and operational testing, emphasis is placed on tests that show that the plant complies with the specification and is capable of performing its emergency role under all conditions of operation. 5.4.1 Tests in manufacturer's works
In general, the object of the works tests is to show that the plant complies with the specification, schedules and previously approved drawings. Prior to tests taking place, detailed test schedules are agreed between the manufacturer and CEGB staff. The latter usually witness the principal tests, whilst other tests can be carried out by the manufacturer, so long as the results are submitted to the CEGB for scrutiny. .1u.k -iliary plant As far as is practical, all items of auxiliary plant are fully tested in the respective manufacturer's works before assembling them with the diesel generator. Such tests include hydraulic pressure tests on oil coolers, valves and piping, water coolers and tanks, air compressors and their auxiliaries. All rotating plant, such as air compressors, and all types of pumps are subjected to running tests over the full specified range of duty. Tests on motors prior to assembly with their driven items are covered in Chapter 7. Generators and exciters The following tests are carried out on each generator assembled for running with its exciter and driven by a temporary motor, in the manufacturer's works, before coupling to the diesel engine: • Demonstration of compliance with vibration requirements.
Chapter 9 • Heat runs on open-circuit, short-circuit and full kVAr loading to determine temperature rises of ge n , erator and exciter. To prove the design fully, the first generator of each size in a particular contract is subjected to the following additional tests: • Using test slip rings, determination of generator and exciter open-circuit and short-circuit and loss curves. • Oscillograph and analyser measurement of the gen, erator phase and line voltage at no-load, no rma l voltage. • Sudden three-phase short-circuit applied to generator terminals with generator running at no-load, normal speed and 100 07o voltage. From this test reactances are calculated from the current envelopes. • Check of radio interference suppression. Combined tests on complete diesel generators After checking such details as cylinder head nut torques, tappet clearances, pump drive chain tensions, crankshaft deflections, correct charging with oil and correct functioning, charging and priming of all auxiliary systems; each diesel engine, fully assembled with its generator, exciter, governor, AVR and auxiliary equipment, is then subjected to the following combined tests: • Alignment check of complete units. • Cold, standby and hot starting tests. At least five starts are performed for each condition, defined as follows: Cold Engine at ambient temperature with no auxiliary oil and water heaters in operation Standby Engine at temperature attained by operation of oil and jacket water heaters at normal thermostat settings and normal ambient conditions Hot Engine at a temperature as attained not more than five minutes after shutdown from a full-load run with stabilised temperature rises • Run at normal speed and highest overspeed permitted by the manufacturer for five minutes to check the balance of rotating parts and compliance with vibration requirements. A typical figure for highest permissible overspeed for 5 minutes is 7/7o.
• Resistance and insulation resistance of all windings.
• Run at full rated output by use of artificial electrical loading facilities for a sufficient length of time to ensure that steady working conditions have been 01 reached, followed by a one hour run at 10 0 overload. Records of temperature attained on the unit are taken.
• High voltage test on all windings.
• Fuel consumption tests.
• Insulation and high voltage tests on all wiring and equipment.
• Governor tests, including load acceptance and rejection tests.
• Determination of generator magnetisation and loss curves, using exciter field current as a variable parameter.
794
Diesel generators qs to show the time taken from start-up to acre ce of full-load with the unit initially in the • , otan (as defined above). : ciLiby condition tests of control panels set up tempor• oper.ltionalcp.ice. including automatic starting and irii , s alarms and protection devices. :,;1,ii,1 01T1 equipment, +v,t% dorm and sudden short-circuit tests out on generator (see generator tests
•
,IireaLl,,. carried d• _load operation endurance test, to demonstrate the • \ of :lie unit to accept load and run satisfac, 0 0, after a continuous period of 48 h at synchro„ 00 speed, normal voltage and zero load. During of fuel consumption, vibration, ,[ 1 [ ,: run, checks 'must discoloration, etc., are made at regular inters als. .\fier the 48 h run, the diesel generator is subii:cted to the load acceptance test determined most
onerous from the governor tests above.
Stage 2 — Isolated system tests Testing of systems to the maximum extent possible without connecting the diesel generator to the operational system. Stage 3 — Operational system tests Proving of the diesel generator unit as part of the essential supplies system of the power station. Stage I — Preliminary tests The following is a summary of a detailed check list agreed between the CEGB and the manufacturer. Complete unit and its auxiliaries: • A physical inspection to ensure correct installation, to installation drawings, and absence of damage. • Check for correct labelling of all plant items. Electrical equipment:
• Voltage regulation measurement from no-load to
• Operational checks on switchgear, including the setting of overcurrent relays.
• lnsulation and high voltage tests on all enginemounted wiring and equipment.
• Test the insulation resistance of power supply cables, motors and small wiring, together with associated control and alarm devices.
I: should be noted that the full output, fuel consump, i i, waveform and no load endurance tests are carried Lt on the first unit of each type and size only. Dependent on the environmental conditions specified :or J particular station, the diesel generator tests are
• Check the direction of motor rotation.
LlI Lload and vice versa.
.1 , o sometimes carried out to ensure compliance in .
Stage I — Preliminary tests Preparation and testing of individual items of equipment or small subsystems prior to functioning as a system.
:ie following areas:
• Seismic withstand. • I Iiirh wind withstand. • Proof against fire protection sprays. 5 4.2
Tests at site
eting is normally a repeat of certain works tests to reveal any damage in transit to site, to hat the diesel generator and its auxiliaries have ' n correctly assembled and that the performance on i! miunie loads complies with manufacturer's guaran--.,. Test results are compared with those obtained H.'Lng. works tests and any significant deviations are •
...
.e , tigated and rectified.
Prior to the site testing phase, the manufacturer _! 7', e‘i the format of the detailed test schedules with
CEGB, All testing is carried out in accordance with schedules, which are completed and witnessed he manufacturer and the CEGB site construction ;resentatives at the time of the test. These schedules .ice subsequently made available for scrutiny by the f( iB operating staff, the Nuclear Installations In.[Orate or other bodies, as appropriate. ')Lte testing is subdivided into three stages: .-
Earthing: • Physical inspection of all earthing connections to electrical equipment metalwork. • Ensure that the diesel generator unit earthing system is correct to drawings and connected to the main station earthing system. Pipework: • Operation of valves. • Pressure testing. • Comprehensive purging to remove dirt and debris that may have entered during transport to site and erection. Pumps, compressors, fans, etc.: • Check the duration and magnitude of the starting current. • Check for correct operation and setting of control safety and alarm devices. • Raise system to normal pressure and check for leakages. • Recheck operation of control, safety and alarm devices. Tanks and air receivers: • Carry out an internal inspection for cleanliness and absence of damage to internal linings. 795
Emergency supply equipment • Check the overflow/blowdown arrangements. • Check for the correct operation of control, safety and alarm devices, in conjunction with associated pumps/compressors. • Cheek level/pressure gauges, both local and remote. Engine speed controls: • Check the operation of speed setting motor. • Set operation of electrical and mechanical governor
for service. • Check the operation and setting of the overspeed trip switch. Engine mechanical checks: • Recheck cylinder head nut torques, tappet clearances, pump drive chain tensions, crankshaft deflections, engine and generator shaft alignment, correct charging with oil, etc, • Charging, priming and venting of auxiliary systems. • Check engine pressure/temperature sensors. Generator:
Chapter 9 • Check correct operation of generator circuit-breaker, field suppression switch and fuel shut-off valve f rom all trip devices on the diesel generator. Controls: • Check diesel engine remote start and stop controls, including automatic starting circuit. • Check governor and AVR remote 'raise' and lo+Aer, `manual' and 'automatic' controls. • Carry out secondary voltage injection on AVR, Engine first run: • This generally follows the manufacturer's standard commissioning and setting up procedures for no-load running. -
• Record a series of measurements during engine starts to establish the cranking speed at which firing occurs. • Monitor and record various air, water and oil temperatures around the unit until all parameters have stabilised. Governor tests:
• High voltage tests.
• Check engine run-up and shutdown on both the electronic and mechanical governors.
• Retest insulation resistance and check polarisation index of stator winding.
• Check engine behaviour on simulated failure of the electronic governor.
• Check anti-condensation heaters and control circuits.
• Record the rate of rise of speed and governor action during the above tests.
• Set and adjust AVR for service. Local control and alarm panels: • Check AC and DC auxiliary supply voltages and polarities.
• Carry out tests to establish the time taken to vary the engine speed over the range of ±5% of synchronous speed with increasing and decreasing speed.
• Check the pick-up and drop-off values of relays.
• Take engine to overspeed and check the overspeed trip setting.
• Check sequence functions of relays.
• Check range of speed control from the control desk.
• Check functioning of alarm annunciator equipment, including accept, reset, lamp test facilities and the audible alarm device.
AVR tests:
Stage 2 — Isolated system tests Again, this is only a brief summary of a detailed check list agreed hetween the CEGB and a manufacturer. Local alarms:
• Run-up the unit with excitation diode short-circuited to prove protection.
• Check operation of all alarm initiating devices around the plant in conjunction with local alarm annunciator equipment and separate or grouped alarm outputs (as appropriate) to the station central control room alarm system.
• Run-up and shutdown the unit to record cut-in and cut-out points for excitation, and check rate of rise of generator output voltage.
• Run-up the unit with excitation diode open-circuited to prove alarm. • Check excitation failure trips. • Check range of AVR settings. Loading tests:
Protection: • Primary inject current transformer circuits to check balanced current and earth fault protection, including setting of associated relays and AVR current transformer circuit for reactive kVA sharing. 796
During commissioning of diesel generators in a new power station, it is unlikely that sufficient load will be available to fully load the unit. It is therefore usual to bring to site the artificial electrical loading facilities used during works testing. This also provides greater
▪ Diesel generators iicsibilitv in the control of load variations, without with the work of other contractors. The tests follow the manufacturer's standard commisand setting procedures: - and rek.ord various air, water and oil tern• \ion itor the plant when stable conditions pef-,inires around btained at 50%, 100% and 110% kW o ,r
•
j),s p.f. and normal voltage. The time to reach ,bic conditions should also be recorded.
Rc,ular records of the above parameters, including „[, -0 eNhaust temperatures, are taken during a 10 h follows the above runs. Temporary tern✓un chich rerature detectors are attached to busbars, bolted ..onnec.tions and cable tails in the line and neutral ,,:rrninal chambers, to detect any hot spots.
• ..ipplication and throw-off tests: check the performance of the governors • In order to AVR, various block loads are applied and d r he .Ili hroo.n-off, recording voltage, current, p.f. and : Teed. The tests are commenced when the machine 1, at full speed and voltage and normal running 1,:niperatures. Block loads of 25%, 50 (Vo, 75% and ! mt•0 0.8 p.f. are applied, thrown off and reapplied Jlier 10 s.
• In addition to the normal log sheet information, oscillograms of voltage, current, engine speed, turbo..harger speed and fuel rack position are also taken. ftesei starting tests: 'dl starts on each engine are recorded, timed and dated with the reason for start and reason for any
rtidure to start. • siiutle bank starting — after establishing normal ',■ ia- king air pressure in the appropriate receiver, inlet valve is shut. A series of engine starts is carried out to determine the number of starts available from the receiver, and the minimum pressure needed in the receiver to carry out a successful start. fhe tests are carried out on each bank in turn. • •--,% in bank starting — with both air receivers at normal working pressure and their inlet valves shut, a series of starts is carried out to determine the [l umber of starts available. • Repeat start tests — start tests are carried out to .ichie\.e a total of 300 successful starts on all engines ..omprising one type. [he iests need not be carried out immediately followlu g each other. 80% are carried out with the engine in its standby (kept warm) condition and 20 07o are carried out at the hot equilibrium condition.
• The reasons for any failures to start are noted and hc CEGB requires additional start tests if 50 consecutive successful starts without failure are not achieved.
• A standard test log sheet is completed for each run at the end of a 5-minute load run. This includes a record of any leaks, discrepancies between tests and any other anomalies, together with any corrective action taken. Stage 3 — Operational system tests
For this series of tests, the diesel generator is testd in conjunction with the power station auxiliary supply system which, in turn, is connected to the Grid system. They demonstrate as far as possible that the diesel generators can carry out the duties for which they are designed. Synchronising
Phase rotation and synchronising tests are performed prior to synchronising the diesel generator to its associated Essential Services Board for the first time. Governor and A VR performance tests under various system load conditions The extent of these tests can
vary from station to station and depend upon the auxiliary system design. Two examples of typical tests are given: • With the diesel generator at full speed and voltage, two emergency boiler feed pumps are started simultaneously. Oscillograms of voltage, current, p.f. and engine speed are taken. • With the diesel generator carrying a motor load of up to 50%, one emergency boiler feed pump is started. Oscillograms of voltage, current, p.f. and engine speed are taken. Auto starting and auto loading tests
Control systems are adjusted to suit loading expected in service: • All diesel generators are started automatically from a simulated reactor trip signal and are observed to run at their preset speed and voltage conditions with all their auxiliaries in the appropriate condition. • A 'loss of Grid' condition is then simulated by opening the connection between the Grid-fed station auxiliary system and the Essential Services Boards to permit automatic connection and loading of the diesel generators on to their associated switchboards.
• A further test consists of simulating 'loss of Grid' conditions as the initiating event with the diesel generators available for service but at standstill. Observations of run-ups and loading are made as above. 5.4.3 In-service operational testing
In order to ensure that diesel generators are at all ti mes available for their emergency role and able to carry their rated load, periodic testing at intervals not greater than one month is carried out. Each diesel generator in turn is started manually and synchronised as described in Section 5.3.3 of this 797
Emergency supply equipment chapter, and loaded up to its full rating. Any surplus generation over and above that required by the station auxiliary system is exported to the Grid system. The unit is left running until all conditions have stabilised and to allow the operators to check that all auxiliaries are running correctly. Where appropriate, failures of duty auxiliaries are simulated to ensure that changeover to standby auxiliaries takes place correctly, after which service is either restored to the duty auxiliary or the standby unit is changed over to the duty auxiliary. Such tests at nuclear power stations are fully recorded for inspection by the Nuclear Installations Inspectorate. It should be noted that throughout the test, the diesel generator can take up its emergency role immediately, the test being terminated by automatic means (see Section 5.1.1 of this chapter).
6 Additional references E/ESS/EX. 32000: Technical Specification and Schedules for Seismic Electrical Plant Qualification
or
Chapter 9 BS440: Specification for stationary batteries (lead-acid Plante positive type) for general electrical purposes: 1964 (withdraun and replaced by BS6290) BS799: Specification for oil burning equipment; Part 5, Oil stora tanks: 1975
ge
BS806: Specification for design and construction of ferrous pipi installations for and in connection with land boilers: [986
n2
BSI 123: Specification for safety valves, gauges and other sa c etv fittings for air receivers and compressed air installations 1976 BS2594: Specification for carbon steel welded horizontal cylindrical storage tanks: 1975 BS2757: Method for determining the thermal classification of electrical insulation: 1986 BS2869: Specification for fuel oils for oil engines and burners for non-marine use: 1983 BS3605: Specification for seamless and sselded austenitic stainless steel pipes and tubes for pressure purposes: 1973 BS4675: Mechanical vibration in rotating machinery: 1978 BS4999: Specification for general requirements for rotating electrical machines: Part 3: Terminal markings and direction of rotation: 1981 Part 20: Classification of types of enclosure: 1972
CEGB Standard 239903: Piping systems — Low pressure water services
Part 21: Classification of methods of cooling: 1972
CEGB Standard 23992: Piping systems — Oil services
Part 40: Characteristics of synchronous generators: 19 7 2
CEGB Standard 20752: Fuel oil storage tanks
Part 51: Noise levels: 1973
CEGB Standard 989907: Noise limits for new power stations [SI 44-3: Electric Motors Specification 3300 V and above EFS 1980: CEGB General Specification for electronic equipment Smith, G.: Storage Batteries: Pitman: 1971
6.1 British Standards (BS) /35417: Specification for galvanised mild steel cisterns and covers, tanks and cylinders; Part 2, Metric units: 1973
798
0S5000: Specification for rotating electrical machines of particular types or for particular applications; Part 99, Machines for miscellaneous applications: 1973 (1981) BS5169: Specification for fusion welded steel air receivers: 1985 BS5311: Specification for a.c. circuit-breakers of rated voltage above 1 kV: 1976 BS5514: Reciprocating internal combustion engines: performance BS6290: Lead-acid stationary cells and batteries: 1983/84
CHAPTER 10
Mechanical plant electrical services introductio
4.4.3 Motor protection 4.4.4 Brakes 4.5 Lift car and landing equipment 4.5.1 Landing control facilities 4.5.2 Car control facilities 4.5.3 Car lighting 4.5.4 Telephone 4.5.5 Maintenance facilities 4.6 Safety devices and systems 4.6.1 Fireman's control system 4,6.2 Flood control system 4.6.3 Travel interlocks 4,6.4 Lift car emergency hatch 4.6.5 Audible alarm 4.7 Lift shaft lighting 4.8 Earthing
n
2 General requirements Sources of supply 21 Choice of supply 2 /.1 Supply variations 2.1 2 2! 3 Applications 2 2 Motors ratings and supply voltages 2 2.1 Motor 22 2 Design standards 22 3 AC motors 4 2 2 DC motors 2 3 Safety considerations 2 3 I General requirements 23 2 Equipment enclosures 2 3 3 Control and trip circuits 2 3.4 Interlocking 23 5 Emergency trip controls 2 4 Environmental conditions 2 4 1 Ambient conditions 2 4 2 Hazardous atmospheres 24.3 Nuclear environments 2 5 Electronic equipment 2 6 Switchgear and contactor gear 2 7 Radio and television interference 2 8 Noise levels
5 Gas producing and storage plant 5.1 Introduction 5.2 General requirements 5.2.1 Safety assurance and standards 5.2.2 Lightning protection 5.2.3 Motors in hazardous areas 5.2.4 Switchgear and contactor controlgear 5.2.5 Control and instrumentation equipment 5.2,6 Transformer/rectifier equipment 5.2.7 Frost protection 5.2.8 Earthing and static protection 5.3 Hydrogen producing plant - electrolytic cell process 5.3.1 General description of plant 5.3.2 Classification of plant areas 5.3.3 Electrical, control and instrumentation equipment 5.4 Hydrogen producing plant - methanol chemical reaction 5.4.1 General description of plant 5.4.2 Classification of plant areas 5.4.3 Electrical, control and instrumentation equipment 5.5 Methane production plant 5,5.1 General description of plant 5.5.2 Classification of plant areas 5.5.3 Electrical, control and instrumentation equipment 5.6 Nitrogen storage plant 5.6.1 General description of plant 5.6.2 Electrical requirements 5.7 Carbon dioxide storage plant 5.7.1 General description of plant 5.7.2 Electrical requirements
3 Cranes 3.1 General 3 2 Power supply and distribution 33 Crane motor drives 3 3 1 Motors 3 3.2 Motor protection 3 3 3 Motion control - direction 3 3 4 Motion control - speed 33.5 Braking systems 3 4 Control station systems 3 4 1 Cab control 3 4 2 Radio control 3 4 3 Pendant control 3.5 Crane controls, interlocks and limit switches 35.1 Control equipment cubicles 3 5 2 Protective panel 3 5.3 Limit switches 3 6 Anti-collision system 37 Travel motion supply systems 3 7.1 Long travel 3 7.2 Cross-traverse 37.3 Alternative supplies for long travel 38 Crane earthing 39 Crane services 310 SPecial features required for nuclear plant cranes 3 10.1 Duty categories 3 10.2 Design requirements 4
lifts 4 1
Types and general requirements 2 Supplies and distribution 3 Motor room equipment 4.4 Lift drive systems 4 4-1 Electrical 4 4.2 Hydraulic 4
6
CW electrochlorination plant (sodium hypochlorite production and storage) 6.1 General description of plant 6.2 Classification of plant areas 6.3 Electrical, control and instrumentation equipment 6.3.1 General 6.3.2 Production control panel 6.3.3 Sea water feed pumps and strainers control 6.3.4 Transformer/rectifier controls 6.3.5 Sodium hypochlorite storage 6.3.6 Dosing pump controls 6.3,7 Electrical distribution
7 Water treatment plant 7.1 Description of plant 799
11, Mechanical plant electrical services 7.2 Electrical distribution system 7.3 Electrical control 7.4 Motor drives 7.5 Frost protection 7.6 Electrically-operated valve actuators 8 Coal, ash and dust plant 8.1 Coal handling plant 8.1.1 General description of plant 8.1.2 Electrical supplies 8.1.3 Electrical control 8_1.4 Conveyors 8.1.5 Stacker/ reclaimer machine 8.2 Ash and dust handling plant 8.2_1 General description of dust handling plant 8.2.2 General description of ash handling plant 8.2.3 Electrical supplies 8.2,4 Electrical control 8.2.5 Mobile ash hoppers 8.2.6 Ash-grabbing crane 8.2.7 Trace heating 8.2_8 Local control panels 8.2.9 Conveyors 8.2.10 Sump pump, grit pump and dust pump controls 9
Electrostatic precipitators 9.1 General description of plant 9.2 Electrical supplies 9.2.1 415 V switchboards 9.2.2 High voltage control cubicles 9.2.3 Transformer/rectifier equipment 9.2.4 High voltage chamber enclosures 9.2.5 High voltage insulators 9.3 Maintenance interlocking and locking 9.4 Farthing 9.5 Interference suppression
1 0 Fuel oil plant 1 0.1 General description of plant 1 0.2 Pumps 1 0,3 Oil heating 1 0.3.1 Tank heating - electrical
1 Introduction
Chapter 10 10.3.2 Tank heating - steam 10.3.3 Pipe heating - electrical 10.4 Storage tank instrumentation 10.5 Valve actuators 10,6 Lightning protection 11 Air compressors 11.1 General description of plant 11.2 Air compressor drive motors 11.3 Heaters 11.4 Automatic and safety controls
12 Heating and ventilating plant 1 2.1 General description of plant 12.2 Control gear 12.3 Classification of electrical equipment 12.4 Drive motors 1 2.5 Air conditioning units 1 2.5.1 Chiller unit 1 2.5.2 Humidifier 12.5.3 Airheater 12.5.4 Fan 12.6 Water heating plant
12.6.1 Heating elements 12.7 Cabling and terminations 12.8 Water circulating pumps 1 3 Fire fighting equipment
13.1 General description of system 13.2 Controls and alarms 13.3 Diesel-driven fire pumps 13.4 Air compressors 13.5 Trace heating 13.6 Detectors and distributors 13.6.1 Quartzoid bulbs 13.6.2 Heat-detecting cable systems 13.6.3 Smoke detection 13.7 Fire dampers and smoke extraction 13.8 Control cabling 13.9 Batteries and chargers 14 References
This chapter describes the main electrical requirements of ancillary mechanical plant in a modern power station. Such plant, whilst not directly associated with the main generating units, is essential for the operation of the power station. It includes cranes, lifts, gas production and storage, electrochlorination, water treatment, coal ash and dust plant, precipitators, fuel oil, air compressors, heating and ventilation, and fire protection.
supply voltage and local distribution requirements. The supplies may be AC, taken directly from main switchboards or distribution boards (which may be located either remote from or local to the plant), or DC from the DC distribution system. The DC distribution system is supplied by battery systems incorporating charging equipment supplied from the electrical auxiliaries system. The following supplies are available in most modern power stations:
2 General requirements
• 11 kV, three-phase, 50 Hz, resistance earthed, with a maximum symmetrical short-circuit fault level of 750 MVA (39.4 kA).
2.1 Sources of supply 2.1.1 Choice of supply
The electrical systems of ancillary mechanical plant are fed from the power station electrical auxiliaries system to suit the specific requirements of the plant in terms of load, security of supply, limitations on 800
• 3.3 kV, three-phase, 50 Hz, resistance earthed, with a maximum symmetrical short-circuit fault level of 250 MVA (43.8 kA). • 415 V, three-phase and 240 V, single-phase, solid earthed, 50 Hz with a maximum symmetrical short circuit fault level of 31 MVA (43.8 kA). • 110 V, single-phase, 50 Hz, one pole solidly earthed from one or two sources, for instrumentation supphes.
,
General requirements Nominal battery voltage
[() V. single-phase, 50 Hz , centre-point earthed, for •. „applies 1 w small tools through socket outlets.
48 V 110 V 240V Nominal working (float) voltage 54 V 121 V 270 V
o v DC from a battery system, earthed through a • e earth fault relay connected from the mid• onnected between the negative and c root L f a resistor Poles. a battery system, earthed in the same DC from • it) V as the 240 V DC system.
Maximum voltage at equipment 54 V 121 V 270 V
„ • -t
V DC from a battery system, the positive pole solid•
e arthed.
2 1.2
Supply variations
supplies are derived from the electrical aux.A. 0 • qics system, they are subject to voltage and fre.•. Nariations and occasional momentary breaks, , i() s\stem disturbances created by the switching of loads. The permitted supply variations stipulated purposes are outlined below and all elec• 7 Jc.,i n i equipment is required to accommodate these - ,j with the exception of motors which are in Section 2.2 of this chapter: 11 kV, 3.3 kV, 415 V, 240 V, 50 Hz supplies Voltage range: nominal + 6%/ — 10% continuously; nominal —2% for brief periods; loss of supply for up to 200 ms followed by a slow recovery to normal system voltage taking up to 180 s, this condition occurring in the event of a major fault on the distribution system being cleared by protection. I rcquency range: 48 Hz to 51 Hz continuously; 47 Hz to 51 Hz for brief periods. transient conditions: up to 5 x nominal voltage
for up to 2 ms. 110 V, 50 Hz instrument supplies Volia,1:e and frequency variation range as (a), but availability supply, usually obtained by a ,iipply changeover system; maximum break in supply 10 ms.
P.
.1 I10 V, 50 Hz supplies, centre-tapped to earth
oltage and frequency range as (a). 240 V, 110 V and 48 V DC supplies. -
•
en fed from battery systems incorporating charger prnent,
electrical equipment is designed to operate a DC supply voltage which is normally at, or near, battery float voltage but which may fall to a value `:,iderably lower than the rated battery voltage in esent of charger failure, as the battery discharges. +roltage ranges and variations are as follows:
Minimum voltage at equipment 43 V 93 V 216 V 2.1.3 Applications
• 11 kV, three-phase supplies are used for a few large motor drives, such as air compressors. • 3.3 kV and 415 V, three-phase supplies are used for motors, actuators and the power requirements of major equipment. • 240 V, single-phase supplies are used for miscellaneous small power requirements, including lighting, heating and motor drives up to 0.75 kW. • 110 V, single-phase instrument supplies are used for control and instrumentation needing high availability but which can tolerate short breaks of up to 10 ms in the event of supply changeover or system disturbances. • 110 V, single-phase centre-tapped supplies are used to supply portable tools through socket outlets, where personnel safety considerations require a maximum voltage to earth of 55 V. • DC supplies are used when supply interruptions are unacceptable, control supplies being at either 110 V or 48 V and motor supplies at 240 V DC.
2.2 Motors 2.2.1 Motor ratings and supply voltages
Motor ratings comply with the relevant British Standard. For power station requirements, motor ratings and supply voltages are categorised as follows: Up to 0.75 kW — 415 V, three-phase, 50 Hz occasionally 240 V, single-phase, 50 Hz 110 V, single-phase, 50Hz 250 V DC and 110 V DC, battery or rectifier derived. 0.75 to 150 kW — 415 V, three-phase, 50 Hz 250 V DC and 110 V DC, battery or rectifier derived. Above 150 kW — 11 kV, three-phase, 50 Hz 3.3 kV, three-phase, 50 Hz DC supplies derived from rectifier equipment. 2.2.2 Design standards
The basic requirements for motors associated with ancillary mechanical plant are the same as those applied 801
Mechanical plant electrical services for main plant auxiliaries and are based upon the appropriate British Standards, as qualified by CEGB standards. Typical main plant auxiliary-drive requirements and the selection of motors are discussed in detail in Chapter 7. An outline of the requirements applicable to the majority of motors is given below. Rating up to 0.75 kW General design is in accordance with BS5000 Part 11(1]. Motors are continuously rated in accordance with BS5000 and suitable for continuous operation in 40 ° C ambient, Winding temperature rises are in accordance with BS5000 [1], except that Class B temperature limits (130 ° C) are applicable, even though Class F insulation may be used. Motors are capable of three consecutive starts, fifteen starts per hour and of operating under varying supply conditions, as follows. AC motors and DC motors fed from rectifier equipment must operate continuously at rated load with supply frequencies of 48 to 51 Hz and voltage variations of +6% of nominal, and must also be capable of short term operation under emergency conditions with supply frequencies down to 47 Hz. In addition, when specified for essential duties, motors must operate continuously at 75% rated voltage and 50 Hz frequency for periods up to 5 minutes and be capable of recovery to normal operation following a supply interruption lasting up to 0.2 s. DC battery-fed motors are required to operate continuously with supply voltage variations of +10% of nominal and for up to 30 minutes at 80% of nominal. Motor enclosures are built to one of the following standards, as classified in BS4999 (21: • Drip proof to IP22 — protected against solid objects greater than 12 mm and dripping water when tilted up to 15 ° . • Totally-enclosed to IP54 — protected against dust and splashing water. • Totally-enclosed fan-cooled to IP54 for indoor use and 1P55 — protected against dust and water jets — weatherproof for outdoor use. Ratings above 0.75 kW and up to 150 kW General design is in accordance with BS5000 Part 40 [l]. Motors are suitable for continuous operation in 40 ° C ambient. Winding temperature rises are in accordance with BS5000 [lb except that Class B temperature limits (130 ° C) are applicable, even though Class F insulation may be used. Motors are capable of two starts in succession, followed by a 30-minute cooling period before another attempt at starting is made, and of three equallyspaced starts per hour under normal running condi802
Chapt er 10 tions. Also, they must be capable of starting when the supply voltage is 80% of the nominal. Windings and insulation are designed to have a minimum life of 18 000 starts and bearings are designed for 40 000 hours' running. The AC and DC supply variations which the motors are required to operate under are the same as thos e described above for motors rated up to 0.75 kW. AC squirrel-cage induction motors are started direct_ on-line at rated voltage. Pull-out torque is specified as not less than twice full-load torque for all induction and commutator motors. Most motors have a maximum continuous rating ( MCR). When appropriate, motors may have a duty type rating (DTR) or short term rating (STR). Motor enclosures are built to one of the followin g standards as classified in BS4999 [2]: • Drip proof to IP22. • Totally-enclosed to IP54. • Totally-enclosed fan-cooled to IP54. • Totally-enclosed air-cooled with an integral heat exchanger to IP54. • Totally-enclosed air-cooled, with a machine-mounted heat exchanger to IP54 for indoor use and 11 3 55 weatherproof for outdoor use. The maximum rating of 415 V, three-phase 50 Hz motors is generally 150 kW. These motors are controlled by contactors incorporating overload protection and protected against short-circuit by fuses. Ratings of ISO kW and above General design is in accordance with BS5000 Part 40 (lb The operational requirements for this range of motors are generally as described above for ratings above 0.75 kW and up to 150 kW, except that machines of 1500 kW and above are totally-enclosed, closed air circuit, with water-cooled heat exchangers, either machine or separately mounted. The maximum cooling water temperature is specified as 30 ° C. All 11 kV motors are protected by circuit-breakers. 3.3 kV motors are protected either by motor switching devices incorporating fuse protection or by circuit' breakers. Circuit-breaker-fed motors are equipped with terminal boxes capable of withstanding the full system three-phase symmetrical fault level.
2.2.3 AC motors Cage induction motors Three-phase cage induction motors are the most widely used for ancillary mechanical plant demanding constant speed drives because of their low cost and high reliability. They are discussed in detail in Chapter 7. -
General requirements h e development of electronic control techni uipment, uipment the use of cage induction motors es anu eq to %ariable-speed drives can provide an economic alter.; traditional AC types, such as slipring induc ,I.JON,e to d ,2ominutator motors. The various techniques an eed and torque control are discussed in Chapter 7. • .. r With t
s
t
riitt
induction rrotors
„ Hpr i n o induction motors in conjunction with rotor i.,,:l tatiee_switching contactors are widely used for anjlap, mechanical plant, such as cranes, demanding 1i3ble-5peed drives. Details of this system are included It Chapter 7. 2.2.4 DC motors Ikeause of their higher capital and running costs and ..:reater maintenance requirements, DC motors are used when the operational role precludes the use of riI \C induction motors. This includes essential drives ,, uieh must be independent of AC supply system ,iilures and specialist applications, such as lifts.
2.3.2 Equipment enclosures
Equipment enclosures are designed to provide adequate and appropriate protection against the ingress of water, dust and solid objects likely to jeopardise the safety of plant and personnel, to prevent unauthorised access by personnel and to allow authorised access by personnel for routine maintenance and commissioning purposes. The degree of protection against the ingress of water and solids is categorised in line with British Standard BS5490 [3]; the IP rating most appropriate to the duty must be specified. A brief description, as given in BS5490 [3], of IP ratings appropriate to power station electrical equipment and typical applications is given below: I P30 Protected against solid objects — greater than 2.5 mm.
Indoor equipment in control rooms, equipment rooms.
IP3 I
Protected against solid objects greater than 2.5 mm and dripping water.
Indoor equipment for which protection against dripping water is essential, switchgear.
IP44 Protected against solid objects greater than 1 mm and splashing water.
Outdoor equipment, such as switchgear, which requires to be ventilated and protected against the environment.
[13 54 Protected against dust and splashing water.
Indoor equipment in which the accumulation of dust would be detrimental and protection against dripping water is essential, e.g., electric motors.
IP55 Protected against dust and water jets in any direction.
Outdoor equipment and special situations, such as boiler houses and coal plants, where the environment is particularly harsh, e.g., motors.
IP65 Dust tight and protected against water jets in any direction.
Equipment in exposed wet and dusty situations necessitating maximum protection against the ingress of dust, e.g., valve actuators.
,
23 Safety considerations 2.3.1 General requirements
The basic requirement is to ensure the safety of personnel who are either directly or indirectly associated with he operation or maintenance of the plant, or who may be in the vicinity of the plant when it is operational. In order to meet this requirement, the following objaik es have to be considered as part of the design process: • The plant must be capable of operating safely over the full range of environmental conditions to which it may be subjected for its design life. Hazardous atmospheres must be recognised and taken into account in the overall design. • In the event of failure of the plant, or part thereof, the safety of personnel must not be jeopardised. • The design should recognise that human error can re s ult in the plant being operated incorrectly and ,o should include electrical interlocks, mechanical interlocks and protective devices necessary to ensure safe operation. •
readily accessible means of shutting the plant clown quickly and easily in an emergency should he provided.
▪ When plant control is dependent to a large extent on manual operation, as in cranes, the possibility of an operator collapsing must be considered and the plant designed to fail-safe. • The design must include all reasonable measures to ensure the safety of operating and maintenance Personnel.
Enclosures for equipment to be used in hazardous areas are designed to satisfy the requirements of BS4683 [4] appropriate fc: - the area classification, as defined in
BS5345 [5]. 2.3.3 Control and trip circuits
Control circuit supplies, with the exception of those to switchgear closing coils, are limited to 110 V maximum in the interests of safety. These supplies are normally obtained from the 110 V AC instrument supply system, from the 110 V DC or 50 V DC supply system or from an integral transformer in the equipment, which steps the supply voltage down to 110 V AC. Equipment requiring a secure supply but which is not likely to suffer from the momentary loss of supply or the variations in supply voltage and frequency described in Section 2.1.2 of this chapter, such as a 803
IP" Mechanical plant electrical services control and instrumentation cubicle, is supplied from the 110 V AC instrument supplies system. Equipment requiring guaranteed supplies for control purposes, such as switchgear and contactor gear, is connected to the station 110 V DC or 48 V DC distribution systems. Equipment which can accommodate the occasional supply interruptions and variations in supply voltage and frequency detailed in Section 2.1.2 of this chapter, such as crane control equipment, is normally supplied from integral 110 V transformers. Control circuits incorporate a 'test' selector switch to enable functional checks to be made in the control circuits without operating the plant. This is important, since it not only permits routine checks to ensure the correct operation of the equipment but also verification that protection and safety interlock circuits are functioning correctly. Switchgear closing circuits are connected through 'plant protection interlock contacts' which ensure that the plant can only be started when in a safe condition. Switchgear trip circuits are connected through 'plant protection trip contacts' which complete the trip circuit in the event of plant malfunction, or of a plant condition arising which could jeopardise the safety of operation. Also connected into the trip circuit are contacts on plant protection devices, which operate to complete the trip circuit in the event of a fault developing on the equipment. The 'plant protection trips' and 'plant protection devices' are fundamental to the safety of the plant and are either connected in such a manner that their failure will cause the plant to trip, or, as in switchgear circuits, the protection contacts are wired in a manner which enables the integrity of the wiring, connections and supply to them to be continuously monitored by a supervision relay. 2.3.4 Interlocking
Interlocking takes two forms; mechanical and electrical:
Electrical interlocks include limit switches, pressure switches, position switches and transducer contacts which continuously monitor the state of the plant, and are connected into the control circuit to ensure that the plant can only be operated in a correct sequence, and in safety. These circuits also include circuit-breaker, contactor and relay position contacts, which are crossconnected into other circuits in the control system to ensure that the correct electrical control sequence is followed, subject to the plant state being proved correct by the interlock contacts. Mechanical interlocks take the form of linkages, cams or other mechanisms which prohibit the operation of a device when it is unsafe to do so; for example, by preventing a cubicle door being opened if the supply disconnector is 'on', or by preventing a non-loadbreaking disconnector from being switched 'off' when the associated contactor is 'on'. When it is required 804
Chapt er 10 to interlock between different items of plant or devi ces to ensure that they are operated in the correct sequenc e or combination, coded-key interlocks are widely used Used either singly, or in conjunction with key-exchange boxes, they ensure safe operation and also 'authorise' plant operation and access for maintenance. 2.3.5 Emergency trip controls
Since the majority of power station plant is unattended, it is not general practice to locate emergency trip c on _ trols adjacent to drive motors or plant but rather to incorporate such devices in the control station, which may be either local or remote. Interlocks and strict Operational safety procedures ensure that safety is mai n _ tamed during both normal operation and maintenance . An emergency trip device normally consists of a red mushroom-headed push-to-trip button, with an integral shrouded or key-operated trip release device to ensure that a deliberate action is necessary for the operato r to reset the trip circuit.
2.4 Environmental conditions 2,4.1 Ambient conditions
The design of the equipment has to include adequate protection against the ingress of water and solids, and be suitable for continuous operation over the full range of ambient temperatures or, if the equipment is subjected to radiant or conducted heat, at the maximum operating temperature likely to occur in service. In the interests of standardisation, equipment is generally specified in three classes, as follows:
Ambient Class I Applies to equipment located indoors in a non-corrosive atmosphere, in which the ambient temperature range is 0 ° C to + 40 ° C. Enclosures are protected against falling dust to 1P30 of BS5490 [3]. Ambient Class 2 Applies to outdoor equipment in a corrosive atmosphere, in which the ambient temperature range is — 25 ° C to + 55 ° C. Enclosures are protected against airborne dust to IP44 of BS5490. Ambient Class 3 Applies to equipment in special situations where the atmosphere is corrosive and the ambient temperature range is — 10 ° C to +70 ° C. Enclosures are protected to IP55 of BS5490. For most power station equipment, Ambient Class I is provided for indoor use and Ambient Class 2 for outdoor use, where it may be subjected to sunlight, wind, rain, snow or freezing conditions. For harsh en vironments, such as boiler houses, equipment is specified to Ambient Class 3, in view of the greater risk of water and dust ingress and the wider operating temperature range. Exceptionally high conditions of
General requirements
1 1 1 i d it Y 'd ,h,". , 1 ,' i d e r e
such as may be found underground, are individually and treated as special cases.
Hazardous atmospheres most powe r ;tation environments do not conds, certain areas, such as hydrogen plants, h3zar IrLiuipment for use in hazardous areas complies requirements or 13S5345 [5], which classifies r he ,is zone 0, Zone 1 or Zone 2,
242 .
-
An area in which an explosive gas/air mixture is continuously present or present for long periods. An area in which an explosive gas/air mixture is likely to occur in normal operation. An area in which an explosive gas/air mixture is not likely to occur in normal operation and, if i t occ urs, will exist for only a short time. \I] areas not classified as Zone 0, 1 be non-hazardous.
Or
2 are deemed
2 4.3 Nuclear environments i icior buildings at nuclear power stations present environmental conditions which have to be n into account in the design of electrical equipment r Incillary mechanical plant. 11 .ic equipment is designed to operate in the envi-ormental conditions which occur when the reactor is commissioned, on-load or shut down for main',N,ince. In addition, the possibility of reactor system or seismic disturbances is considered and the .,;I:prncru designed accordingly, having regard for the Iserutional role of the equipment during and following • ern. l'n%ironmental conditions to which equipment may .. .....:\po ,;ed during its operating life are dependent upon Joign of the reactor system and the location of equipment. In addition to the temperature radiation lewls and humidity range occurring 7ing normal station operation; short-term large varia• , t1N in temperature, pressure and radiation levels may during maintenance or reactor system faults. ,
2.5 [
Electronic equipment eli ,,ure that electronic equipment is of consistent
• ;i1J.Ird and suitable for operation in a power station
.•.%ironment, the CEGB has its own specification, EES ".)) [61 v.hich lays down basic design parameters .t .1 , irinent type tests. Electronic equipment is classi• J Jecording to its environment — Class B3/X for -door equipment and Class Cl/X for outdoor equipRequirements appropriate to these classifications ."e ii)ulated in the specification. Because of the 051 ''''' 1Y of electronic equipment to its environment,
these classifications cover environmental temperature, humidity and levels of electrical interference to which the equipment may be subjected during operation. Equipment may be subjected to radio frequency and cable-borne interference. Common causes of radio frequency interference are portable radio transmitters, fluorescent lamps, DC relay operation and the switching of AC supplies. Cable-borne interference reaches equipment in both power and signal lines as a result of coupling at the source and between cables, the main cause being the rapid change of current due to switching and fuse operation. EES (1980) [6] specifies tests designed to demonstrate that equipment is unaffected by levels of interference appropriate to the environmental classification. Environment Class B3/X covers a temperature range of — 5 ° C to + 40 ° C, a humidity range of 5 07t1 to 95 000, and mild levels of radio frequency and cable-borne interference appropriate to control/equipment rooms and other areas associated with power generation plant. Class Cl/X caters for a temperature range of — 25 ° C to + 55 ° C, humidity up to 100% and interference levels si milar to Class B3/X.
2.6 Switchgear and contactor gear Switchgear and contactor gear for use with mechanical ancillary plant is provided to the same standards and specifications as that used elsewhere in the power station, and is described in Chapter 5. 2.7 Radio and television interference All electrical equipment is designed to restrict radio interference to the limits specified in British Standard BS800 [7]. 2.8 Noise levels Maximum levels of noise are specified which (a) satisfy the recommendations laid out in the Department of Employment 'Code of Practice for Reducing the Exposure of Employed Persons to Noise', (b) are consistent with the established limits of person-to-person and telephone communication, and mental concentration, and (c) are consistent with the limits of noise transmission which can be achieved at reasonable cost, to areas beyond the power station boundary. The specified limits in noise level are outlined below: Local to plant
Surface noise level local-to-plant measured at a distance of 1 m from the plant surface is 93 dBA maximum for plant generally and, for plant provided with a noise enclosure, 90 dBA maximum at the enclosure surface and 110 dBA inside the enclosure (if access is necessary when the plant is operational). -
-
Control rooms Background noise level must not exceed 67 dBA at 62 Hz, ranging to 33 dBA at 8 kHz.
805
PP. Mechanical plant electrical services
Chapter 10
Control areas Background noise level must not exceed 83 dBA at 63 Hz, ranging to 54 dBA at 8 kHz.
Off-site The noise level at the nearest residence or community must not exceed 67 df3A at 63 Hz, ranging to 33 dBA at 8 kHz.
3 Cranes 3.1
General
Power station cranes include: • Overhead travelling cranes in areas such as the machine hall. • Goliath cranes in outdoor areas such as the CW pumphouse. • Grabbing cranes, in coal and ash plants. • Travelling stacker/reclaimer machines in the coal stockyard. • Maintenance hoists. • Reactor pile cap cranes. • Reactor charging machines. • Nuclear fuel flask-handling cranes. Cranes provided for power station construction purposes only are not dealt with in this section.
The diversity of locations and operational require: ments of these cranes necessitate specialist requirement s too numerous to describe here. The principal desi gn requirements which apply to the majority of cranes o n a power station site are described in this section. These relate specifically to overhead travelling cranes ar i d goliath cranes but many of them form the basis for the design of the more specialist cranes, such as reacto r charging machines. Specific design features for nuclea r power station cranes are discussed in Section 3.10 of this chapter. A typical cab-controlled crane, as used in turbine halls, is illustrated in Fig 10.1. Cranes vary in rating between 5 t and 350 t, and ma y be equipped with up to two auxiliary hoists. In so me instances, two cranes are required to work in tandem for large lifts, such as turbine rotors. Operational requirements, together with the heavy and frequent usage during the power station construction period, are carefully considered when establishing basic design requirements. Since the cranes may be in service from early in the power station construction period, their design must be adequate for the environmental conditions and power supply variations which occur during that period: these conditions may be more onerous than later, when the power station is operating. The design requirements described in this section supplement or supersede those of British Standard BS466 [8].
SHROUDED MAINTENANCE CAGE WITH LOCKABLE DOOR ACCESS TO LONG TRAVEL GEAR PLATFORM DRIVERS CABIN ACCESS DOOR TO DRIVERS CABIN GRAB RAILS
FIG. 10.1
806
Cab-controlled crane — typical arrangement
SHROUDED LONG TRAVEL CONDUCTORS
Cranes
3.2
power
su
pply and distribution
Ehree-phase three-wire 50 Hz supply is pro\ j., "" for eac h cr adle, direct from a fuse switch in the oNitchhoard serving that area. Prior to II ; witchgcar being commissioned, the site s is used, with variations and limits :ru:tion supply ailed in Section 2.1.2 of this chapter. 11VIc415 \, ,Lipply is connected by cable to a main which ts readily accessible from the Lng Switch operating floor. From there, it is extended by III the downshop conductor system and thence to :0 ,:rane , On the crane is located a further isolating which supplies the crane drive motors through ,A)ntactors. Fuse protection is provided on mdisupplies. Particular attention is paid to jil fuses fitted to the 415 V main supply rat ing of ..\ ieliboard and those on the crane to ensure adequate v
!Jun discrimination. Figures 10.2 and 10.3 show a typical crane supply .trtd distribution system.
3 3 Crane motor drives 33.1
Motors
v i riable-speed motors are normally provided for the ; , r wcipal crane motions, i.e., main hoist, auxiliary hoist fitted), long-travel and cross-traverse. For the maof applications, 415 V. three-phase 50 Hz induconly of ':. , a motors are used; either slipring (with switched toior-resistances) or squirrel-cage types (with thyristor speed control systems). For constant-speed drives, Iiirrel-cage induction motors are normally used, these Hri started direct-on-line. For certain applications in nuclear power stations, 210 V DC motors are used, these requirements being Iscussed in Section 3.10 of this chapter. Motors are .n accordance with British Standards BS5000 flj and 10,4999 [2], as appropriate. They are totally-enclosed, protection to 1P54 for indoor cranes and to 1P55 eatherproof for outdoors. For main hoist, auxiliary hoist, long-travel and cross't:t+erse applications involving cyclic operation, motors .Lt.: suitable for 150 starts per hour and are of duty •:. pe S4 or S5 to B54999 Part 30 [2], with a minimum duration factor of 25%. To cater for long slow main and auxiliary hoist motors are capable of ..ontinuous operation on the first notch speed. 33.2 ')hort
Motor protection
.:ircuit protection on the motor supplies is proJed by by high breaking capacity (HBC) cartridge fuses '0 I3S88 [9]. Motor protection is afforded by magnetic ercurrent relays, fitted with adjustable inverse time Jelay elements connected into each of the three phases. Il otst motions are, in addition, fitted with currentoperated single-phasing protection. 0
These protective devices are arranged to trip the main supply contactor rather than the motion contactor, since the main supply contactor is subjected to a less arduous duty and is therefore less susceptible to failure. An undervoltage protection system is fitted to the main crane supply and connected to trip the main supply contactor when the voltage drops below the operating capability of the motor, i.e., 80% of the nominal value (see Section 2.2 of this chapter). The main isolating switch, main supply contactor, motion contactors and all protection equipment are housed in sheet-steel cubicles mounted on the bridge of the crane. 3.3.3 Motion control — direction Motion directional control is provided by a three-phase, triple-pole reversing-type contactor connected to reverse t wo of the three phases of the drive motor supply. This contactor is manufactured to 3S5424 [10] and ESI Standard 37-1 [11] and is electrically and mechanically interlocked to ensure that only one direction can be selected at any time. 3.3.4 Motion control — speed Speed control of slipring induction motor drives is achieved by a number of motor accelerating contactors controlled by timer devices, which progressively shortcircuit resistances connected in the rotor circuit to give the required acceleration and final speed. This is the most common system in use on power station cranes and is shown on Fig 10.2. Alternative systems for the speed control of squirrelcage induction motors include solid state variablefrequency or voltage control equipment. High integrity, high availability cranes, or cranes utilised for close tolerance fitting operations, are provided with a creep speed control system, in addition to the normal speed control system. A typical creep speed control system consists of a closed-loop in which an eddy-current brake with variable-torque-speed characteristics is coupled to the shaft of the slipring induction motor and used to control its speed within close tolerances (in the order of ± 1%). The motor is accelerated up to the rated speed under rotor-resistance control. By comparing the motor slipring voltage with a reference voltage, the difference between the desired and actual motor speeds is determined, the error signal then being amplified and fed to a thyristor firing circuit to vary the amount of braking. By continuous monitoring of the speed difference signal, the output speed variation is restricted to close limits. In the event of failure of the creep speed system, the drive reverts to the basic rotor-resistance system. The operational integrity and safety of the motion drive is therefore assured, although the accuracy of speed control is i mpaired. 807
Ch a pte r
Mechanical plant electrical services
MAIN
113
HOIST
I6A 70 OTHER C PEE PSP EE TI CON rRoL
L CCP5
UNDERvOL I AilE PROT& C TON
SUPPLY I NPUT FUSES I315A)
SINGLE P.AASING P Ft() IL C TIDN CLOSED LOOP CREEP SPEED CONTROLS CURRENT TRANSFORMERS
OVE R CURREN RELAYS
r
MAINS SUPPL Y CONTAC TOR SWITCHING :IR Cur
MI
EARTH BAR
-v
REVERSING CONTACTOR
EDDY CURRENT BRAKE
MAIN HOIST SERIES LIMIT SWITCH
SELECTION CONTACTS
MAIN HOIST MOTOR C EMERGENCY SERVICE MAIN HOIST BRAKES
MAIN HOIST MOTOR ROTOR RESISTANCE SWITCHING NETWORK
FIG. 10.2
808
Typical main and auxiliary hoist supply and distribution system
Cranes
AUXILIARY HOIST A. CREEP
FAST
Suar, I HRu r FUSES
SINGLE PHASING PRO TEC CON
SINGLE THAT PROTEC T ION
OvERCURREN RELAYS
0.,EREAJRREN
RELAYS
EARTH BAP
EARTH BAR
Tb
REvE R , ;■ NG CON TAG Top
REVERSING CONTACTOR
EA ST r TWITCH
'CREEP' LIMIT SWITCH
'
'CREEP MOTOR
FAST MOTOR
AUXILIARY HOIST FAST
CREEP
SUPPLY I NPUT FUSES
SUPPLY itiou T FUSES
SINGLE PHASING PROTECTION
OVERCURRENT RELAYS
OVERCU BRENT RELAYS
EARTH BAR
EARTH BAR
REVERSING CONTACTOR 'FAST' LIMIT SWITCH
REVERSING CONTACTOR
'CREEP' LIMIT SWITCH
'
FAST MOTOR
FIG.
10.2 (cont'd)
'CREEP MOTOR
Typical main and auxiliary hoist supply and distribution system 809
Mechanical plant electrical services
Chapter 10
MAIN TRAVERSE
MAIN TRAVEL
II
16A
504
CL OSF. 0 LOOP CREEYSPFE D CONTROLS OVE RC U RISE N RELAYS
• EARTH BAR
II II II
•
24
REVERSING CON rAC TOR 0
SELECTION CONTACTS
MAIN TRAVERSE MOTOR
• I
I MAIN TRAVERSE MOTOR ROTOR RESISTANCE SWITCHING NETWORK
•
• •
MAIN TRAVEL MOTOR ROTOR RESISTANCE SWITCHING NETWORK
FIG. 10.3 Typical travel and traverse supply and distribution system 810
Cranes Creep South/slow South/ fast South.
Braking systems 3.3,5motions are equipped with electrically-operated or 'electromagnetic solenoid' brakes which ty and rating defined by BS3579 1121. The 3 du design ensures that the brake is autopplied if the supply to the associated drive a ,2ttre5 10.2 and 10.3 show typical arf j ik. Fi 'thrustor' brakes on a crane, one being LieLi for each travel motion and two, emergency ,er\.ice. being provided on the main and auxiliary The brakes are supplied from the motor mo(ions. motion contactor and provide a fail-safe o f ihe On the hoist motions, the emergency brake as a back-up to the service brake, if the latter
'
(6)
Cross-traverse control Creep West/slow West/ fast West Creep East/slow East/fast East.
(7)
Long travel limit override
Key-operated.
(8)
Cross-traverse limit override
Key-operated.
(9)
Anti-collision system Key-operated. override
..,[.
(10) Warning hooter
3.4 Control station systems
(11) Crane floodlights on/off switch
To floodlight operating floor.
3.4.1 Cab control control consists of a driver's cab slung under ne end of the crane bridge, equipped with all devices ., c ary for the manual control of the crane. The zt.inernent suffers from a number of disadvantages has been superseded by radio control in certain Ntations, when the operational advantages justify
(12) Crane bridge lights on/off switch
To control access lighting.
on/off switch.
• !.... additional cost. I he disadvantages of cab control are as follows: • The site and disposition of the cab imposes a reiriction on hoist and traverse movements. • [he driver is positioned high above the operating floor and so cannot perform operations without :he aid of an assistant on the operating floor. • Parking and driver access is normally restricted and —in necessitate the crane being manned for long periods during a prolonged handling sequence. .\pkal cab control layout is shown in Fig 10.4. rdne operator controls are provided as follows: inotiun control devices are levers, which return to 'oil position
v. I len released.
Ke ,,, -operated on; off
Finervency-stop pthhbutton ) \lain hoist control
• tRiliary hoist control
l ung travel control
The key has a code unique to the crane and is trapped in the 'on' position, to prevent unauthorised operation of the crane. Described in Section 2.3.5 of this chapter. Creep raise/slow raise/ fast raise. Creep lower/slow lower/ fast lower. As for main hoist. Creep North/slow North/ fast North.
The above controls operate directly into the contactor control circuits, through a control station selection device located adjacent to the 'local' controls on the crane bridge-mounted protection panel.
3.4.2 Radio control
Radio control overcomes the shortcomings of cab control and offers the following advantages: • The crane operator is at operating floor level and unrestricted, thereby enhancing crane operating efficiency. • Parking of the crane is not governed by personnel access requirements, except for maintenance purposes. • The full span of the bridge can he utilised for traversing and hoisting operations. The system is not without disadvantages, however, and these are summarised below: • Radio control is susceptible to interference and elaborate safeguards must be included in the system to prevent malfunction. • The control system is more complex, since it requires a transmitter, receiver and interface relay equipment. • The portable transmitter/control units are susceptible to accidental damage and abuse if their usage and storage is not strictly controlled. An outline of the radio-control system is given below. The control functions provided by a body-worn transmitter/control unit are the same as those described in the previous section. A typical layout is shown in Fig 10.5, 811
Mechanical plant electrical services
Chapter 10
CROSS TRAVERSE CONTROL (6)
MAIN HOIST CONTROL (3)
CROSS TRAVERSE OVERRIDE (8).
LONG TRAVEL LIMIT OVERRIDE (7).
• KEY OPERATED
FIG. 10.4 Cab control layout
I 8.19S I
I
Loorepi
LOWER
NORTH
EAST
RAISE Lima SOUTH ASS OVERHOIST '13' RIDE TRAVEL
WEST
OF F
TRAVERSE
ON
LOWER
•:0 \\, 0
START
RAISE mAi N HOIST
ALARM
RAISE AUX HOIST A.
LPGHTS
Flo. 10.5 Radio transmitter control layout
Radio control systems are VHF, UHF or, more usually, LF, and comprise a transmitter/control unit, which is carried by the crane operator on a waist/ shoulder harness, plus a receiver and interface relay equipment, the last two items being located on the crane bridge. Contacts on the interface relays are connected through sequence relay equipment to operate the crane control contactors. A typical LF radio control system uses coded, continuously-transmitted multi-frequency signals to safeguard against malfunction of the crane due to external interference. For each crane control to function, a 812
minimum of three radio frequency signals and a master security-frequency signal must be transmitted simultaneously. Unique control frequencies are allocated to each crane to safeguard against the incorrect matching of transmitter and crane. As a further safeguard, the transmitter range is limited to approximately 60 m. 3.4.3 Pendant contra!
The simplest and most economic means of crane control is by pendant control station. Applications are necessarily limited to lower-capacity cranes, such as
Cranes ed in diesel generator houses and ancillary hose us where lifting needs are relatively small plant houses, d limited. In The control station is either of the double-insulated ,aitern, with a metal insert to give mechanical strength, metal case shrouded in rubber. Pushbuttons are '„ a trouded to prevent accidental operation and are selfwhen released. A typical pendant control sta.c , L, (t i ng :on is shown in Fig 10.6. An earth continuity conductor is incorporated in the -endant supply cable and is connected to the control :iaiion metal insert or box. t
.
a
RAISE A)
3.5 Crane controls, interlocks and limit switches 3,5.1 Control equipment cubicles
L , LOWER .1
w
CONTROL OPERATIONAL SWITCH
a
The control equipment is housed in a suite of cubicles
lounted on the crane bridge: it comprises protec!i on equipment, stator contactor controlgear, rotor ontrolgear, timing relays, sequence relays, speed conirol equipment and related electrical control equipment. These cubicles have protection to 11'54 of BS5490 [31 or indoor use and to 1P55 weatherproof in outdoor ,auations. One of the cubicles houses the 415 V main supply holating switch. A system of coded-key interlocks is provided to prevent any of the control cubicle doors irom being opened when the main supply isolating ,itch is 'on', and to prevent the isolating switch being ,:iosed when any door is unlocked. Figures 10.7 and 10.8 show the disposition of equipment on the bridge and crab unit of an overhead travelli ng crane. ri
0
TRAVEL 6 TRAVERSE '3 LIS OVERRIDE
(o WARNING HOOTER
)
I ' S OU ! Ho) ,
A
3.5.2
Protective panel
One of the suite of control cubicles, the protective panel, accommodates the 415 V main supply isolatmg switch, the main supply contactor, motor overload protection devices, fuses, transformers, rectifiers and other components necessary for the control of the crane, a complete set of motion control pushbutton -+I.itches for maintenance and testing purposes and a .: onirol selector switch. The last item has four positions: Remote
Allows the crane to be operated from the normal control panel only.
Local
Allows the crane to be operated from the protective panel only.
Remote test
Allows the crane remote control circuits to be checked, with the main supply isolating switch 'off'.
Local test
Allows the crane local control circuits to be checked, with the main supply isolating switch 'off'.
NORTH
j
a
1,
EMERGENCY STOP
(0 EAST 0)
WEST 0)
Flo. 10.6 Pendant control station 813
Mechanical plant electrical services
Chapter I()
MAIN HOIST RESISTOR PANEL MAIN HOIST CONTACTOR PANEL
MAIN HOIST RESISTOR PANEL
CROSS TRAVERSE AND AUXILIARY HOIST PANEL CROSS TRAVERSE AND LONG TRAVEL RESISTOR PANEL
CRANE PROTECTIVE PANEL
MAIN HOIST RESISTOR PANEL
LONG TRAVEL CONTACTOR PA NEt.
I NT
R
E MEDIA TE RELAY PANEL
DOWNSHOP COLLECTORS
END CARRIAGE
EASTSIDE
LONG TRAVEL CREEPSPEED CONTROL UNIT
MAIN HOIST CREEP SPEED CONTROL UNIT
MAIN HOIST TOP SUSPENSION
MAIN HOIST SERVICE BRAKE
CROSS LEAD TOWING BRACKET •
' 71
CROSS TRAVERSE CRAB
NORTH SIDE
SOUTH SIDE
AUXILIARY HOIST ACCESS LADDER
FIG. 10.7 Typical crane bridge layout 814
MAIN HOIST DRUM
AUXILIARY HOIST MAINTENANCE PLATFORM
Cranes
CRANF. r4TFC TIVE
LONG TRAvEL PANEL
STAIN HOIST RESISTANCE PANEL
MAIN HOIST PANEL
mA, TT NANG! .,ST KT r '
CROSS TpAvERSE AND PANEL
AUXILNR R
, • R.RVE AVE ,NNER LI
l T 5 1 1 5511
HOIST ULTIMATE LIMIT SNITCH 10 1S T MOTOR
•
I
_ HOS rSeIIAlcE BR AKE
ow+THT
E
LI
K AR T HOIST
A
A
0 00. S.
CROSS TRAVERSE GEARBOX
HOIST GEARBOX
"
A.
'" TCN
CROSS TRAVERSE
Nc'e
RETAKE
FT A NE HOTS , ' TA E EFSPF D r O SNIROC CROSS TRAVERSE MOTOR
TOP SUSPENSION PULLEYS MAIN
HMS A RRE L MAIN 101ST DRIVE SHAFT
TRAvERSE
SONG TRARHEL L A.TI ' SNITCH
- MIT SWITCH
T RAVERSE
HOIST OVERWINCHOVERLOWER
AT. r SNITCH
LIMIT
swirci4
=---
7-
I NTERMEDIATE
RELAY PANEL
•HAVEL ORTVE TANNER
LONG TRAVEL GEARBOX
LONG TRAVEL MOTOR LONG TRAVEL CREERSPEED CONTROL UNIT
BRAKE
CROSS TRAVERSE LONG TRAVEL RESISTANCE PANEL
MAIN HOIST RESISTANCE PANEL
FIG. 10.8 Typical crane crab layout
Figures 10.2 and 10.3 show typical distribution and 0 itching arrangements. 415/110 V transformers are provided to supply ,ontrol circuits and crane auxiliary circuits, such as illk way lighting and anti-condensation heaters. ,
3.5.3 Limit switches Limit switches are provided in hoist, long travel and ross-traverse motion circuits. They are metalciad and mechanically operated, normally having a self-resetting action in both directions, and are positioned so that :hey are accessible from the crane bridge walkways for maintenance purposes. On hoist motions, limit switches are connected into the motion contactor control circuit to prevent overlowering and over-hoisting. Over-hoisting is more dangerous, and to safeguard against contactor or limit ,
switch malfunction, a back-up system is provided consisting of two limit switches connected directly into two phases of the 415 V, three-phase supply to the hoist motor. These limit switches are manually reset and no override facility is provided. On long travel and cross-traverse motions, four limit switches are installed in each direction of motion to prevent overtravel and safeguard against limit switch or contactor failure. The first limit switch trips the motion contactor, the second limit switch trips the main supply contactor and the third and fourth limit switches, which share the same position, trip motion and main supply contactors, respectively. Limit switches are positioned as follows: The first limit switch stops the crane when travelling at fast speed before it reaches the second limit switch. 815
Chapte r 10
Mechanical plant electrical services The second limit switch stops the crane when travelling at fast speed before it reaches the third and fourth limit switches. The third/fourth limit switches both stop the crane when travelling at slow speed before it reaches the rail buffer stops. Travel limit switches do not reset until the crane operating arm reverses past them. The travel limit override control, referred to in Section 3.4.1 of this chapter, allows the crane to be driven over the first and second Limit switches at slow speed and up to the third/fourth limit switches. A second override control allows the crane to be driven over the third/fourth limit switches at slow speed up to the rail buffer stops. When travel motions have single-speed motors, three li mit switches only are installed, the first to trip the motion contactor and the second and third, which share the same position, trip the motion and main supply contactors, respectively. The limit switches are positioned as follows: The first limit switch stops the crane when travelling at fast speed before it reaches the second and third li mit switches. The second/third limit switches stop the crane when travelling at fast speed before it reaches the rail buffer stops. A travel limit override enables the crane to be driven at slow speed past the first and second/third limit switches up to the rail buffer stops. Travel limit override controls spring-return to 'off' to prevent pre-selection and to ensure that overriding requires a deliberate action.
3.6 Anti-collision system Sometimes two cranes share the same rails and are, therefore, provided with an anti-collision system to prevent them being driven into each other. When the cranes are required to be used in tandem for large lifts, a key-operated anti-collision override switch is provided at the control station (see Section 3.4.1 of this chapter) to enable them to be driven up to each other for coupling purposes. Anti-collision systems are of the optical, radar or potentiometer-wire type. The last system has been used in a number of CEGB power stations and is briefly outlined below. A potentiometer wire system consists basically of a low resistance register wire and a potentiometer wire running parallel with each other and with the downshop conductor systems of the two cranes. The poten816
tiometer wire is connected across the secondary winding of a supply transformer which causes a voltage d rop along the wire of the order of 24 V. Electronic units on each crane are connected to the potentiometer wi re by collectors and interconnected via collectors and th e register wire. The potential difference along the length of potentiometer wire between the collectors of the tw o cranes is monitored by the electronic units, the control loop being completed through the register wire. As th e cranes approach each other, the potential differenc e between the pick-up points on the potentiometer wire decreases until the minimum approach distance of the two cranes is reached. At this point, the electronic units trip the crane motion contactors and stop the cranes .
3.7 Travel motion supply systems All systems are rated for a 31 MVA 415 V fault level, 3.7.1 Long travel
The 415 V three-phase 50 Hz supply and earth continuity connections to the crane comprise four fully. shrouded downshop conductors located immediatel y below the crane rails. These conductors are made of hard-drawn copper, copper/steel laminate or phosphor bronze, as dictated by current rating and volt-drop requirements. Protection against accidental contact with metal objects is provided by insulating shrouds. Connections between the downshop conductors and the crane are made by short-boom type collectors,
which are accessible from the crane bridge for maintenance. The 415 V three-phase 50 Hz supply from the Station Switchboard is connected into a quick-break, threeposition (service, isolated and off/earth) supply isolating switch positioned at operating floor level and, ideally, half way along the length of the downshop conductors to minimise volt-drop on the system. The 415 V supply connections from the isolating switch to the downshop conductors are made in armoured cable. At each end of and, in some instances, at regular intervals along the downshop conductors, warning lamps are fitted to indicate to personnel in the crane operating area that the conductors are energised. At each location, three red-coloured indicating lamps are connected in star formation to the three phases of the downshop conductors through HBC fuses. Fully-shrouded downshop conductors are used for the majority of overhead travelling cranes in a power station. For goliath cranes, travelling cable systems or totally - enclosed rigid conductor/collector systems, mounted just above floor level, are used to satisfy personnel safety and weatherproofing requirements. For overhead cranes with limited long-travel require ments, a travelling cable chain system may be considered instead of a fully-shrouded rigid conductor system.
Cranes 31, 2
cross - trave
rse
and control connections between the 1 Y s uPP p eerbridge and the crab unit, which traverses the , rin e bridge and accommodates the hoist equipment, 'lan by a circular or flat-form travelling cable ro d e in which the cables are looped between trolleys. j in unction boxes on the bridge are tertni nated po;Aer supplies are run in separate cables b Ja . lie control connections to protect control funcls and operating personnel from the effects of supply : ,„ i faults. Control cables have an overall screen to against interference from the supply cables. [ , r oect 3.
73 Alternative supplies for long travel
two cranes share the same rails, they are devied so that each crane can be supplied from either si of downshop conductors. This necessitates two es collectors and a changeover disconnector on each Jane. A coded-key interlock exchange-box system is 'voided to ensure that both downshop conductor , u pply isolating switches are in the 'off position before caner crane changeover disconnector can be operated. fhis system safeguards against unauthorised operation of the changeover disconnectors and allows non-load :naking/breaking disconnectors to be used. %% here
3.8 Crane earthing n earthing system is provided on the crane which Jisures that the crane structure and metal cases of Ail electrical equipment, including metal conduit and , runking, are all effectively earthed. This is connected :0 the Station earth through the earth continuity conJuctor forming part of the downshop conductor system ice Section 3.7.1 of this chapter), an earth continuity .oliductor down to the supply isolating switch and lioice to the earth mat. Crane rails are bonded with earthing tape across oints and connected to the station earth. 3.9 Crane services Pie following services are provided on cranes, as aprrupriate: floodlights 110 V tungsten or discharge-type floodkghts are provided on the side of, or below, the bridge 'Li illuminate the crane handling area. A 415/110 V raiiNformer is provided on the crane for all lighting and heating services. The floodlights are controlled !tom the control station by a contactor, each luminair `N.Ing separately fused. ii(ess lighting Crane access ways and driver's cab fitted) are illuminated by 110 V tungsten bulkhead [uininaires controlled by a switch fuse. W
drning hooter Each crane is provided with an audible warning device to warn any person situated within
the crane operating area. It is supplied at 110 V from the 415/110 V control circuit transformer and controlled from the control station by a contactor. Maintenance socket outlets A system of 110 V AC socket outlets is provided on the crane bridge to facilitate the use of hand lamps and portable tools. To enable maintenance work to be carried out with the crane disconnected from the 415 V supply, 110 V socket outlets are provided on the building structure adjacent to the crane rails and a flying lead is used to connect between them and the crane bridge. This allows work to be carried out on the crane in the event of a breakdown in any position.
3.10 Special features required for nuclear plant cranes 3.10.1 Duty categories
Cranes for the handling of plant or maintenance of equipment within the reactor building and associated areas in a nuclear power station are categorised according to their duties as follows: Category A — Safety-related cranes This category comprises high availability, high integrity cranes which are required to handle critical loads in areas where a breakdown or malfunction during the handling of a load could give rise to a radiological hazard or be the cause of damage to the reactor structure, safety-related systems, or essential ancillary equipment. Category B — Availability-related cranes Cranes in this category are needed to handle loads related to unit availability, such as unit auxiliary plant and plant items with long delivery lead times, lack of availability of which would jeopardise unit availability. Category C — Auxiliary cranes These cranes are for general maintenance purposes on non-essential auxiliary plant and for use in areas where unit availability will not be prejudiced by their breakdown or malfunction. 3.10.2 Design requirements
The design requirements for Category B cranes are
detailed in the preceding paragraphs of this section, whilst those for Category C are less onerous. In view of the essential nature of Category A cranes and the stringent operational safety requirements necessitated by their location, the requirements applicable to Category 13 are supplemented by those briefly outlined below: (a) Seismic qualification. The cranes, together with
their control gear, are designed to ensure that a load is held and control retained in a safe manner during a seismic event. 817
Mechanical plant electrical services (b) Control system security. All crane components and systems which are essential for the security of a load are designed to ensure that a single failure will not result in an incident. This is achieved either by built-in redundancy or by conservative design. (c) Hoist motions. Preference is given to the provision of two independent systems, either of which is capable of handling the rated load in the event of failure of the other. If only one system is practicable, then a higher safety factor is applied for design purposes. When separate drive motors are employed, particular attention is paid to the need for them to be synchronised and equally loaded in operation. Hoist overload systems are provided to ensure that the hoist rating is not exceeded. Such a system may consist of load cells operating into the crane control circuit. In addition to the service and standby brakes described in Section 3.3.5 of this chapter, each hoist is equipped with an emergency brake capable of retarding and holding the rated load. The emergency brake is not deployed in normal operation, operating only in the event of a hoist malfunction, e.g., overspeed, incorrect rotation, load hang-up, or when the main supply contactor trips. (d) Travel motions. Independent drive units are provided on each end carriage for long travel. Each unit is equipped with automatically operated service and standby brakes, those on either drive unit being capable of stopping a fully-loaded crane from full speed in the event of the other unit failing. (e) Motors. 240 V DC drive motors may be used in preference to AC units when security of supply and crane operation are of paramount importance. (f) Cables and wiring. When cranes are exposed to nuclear radiation, the use of PVC insulated cable and wiring, which is prone to degradation in such environments, is avoided. Polymeric cables are used in preference.
4 Lifts 4.1 Types and general requirements There are three categories of power station lift: passenger, goods and construction lifts. Lift design and construction, in general, is in accordance with the following British Standards: BS 2655 [13], BS5655 [14] and BSCP407 [15]. Construction lifts are installed early in the power station construction programme for use as passenger or goods lifts during the construction period. Control gear is provided suitable for the harsher environment existing during this period, with protection to 1P55 weatherproof of BS5490 [3] being specified. 818
Chapter 10 Goods and passenger lifts are provided for use durin g the power station commissioning and operational Periods, by which time the environment is controlled. Control gear is therefore provided with less protectio n — IP31 in control buildings, offices and workshops and IP54 in boiler houses and reactor buildings. Some passenger lifts are designed to accept stretche r _ borne personnel.
4.2 Supplies and distribution Three supplies are provided to each lift motor room: • 415 V three-phase 50 Hz three-wire. • 240 V single-phase 50 Hz. • 240 V DC. The 415 V three-phase 50 Hz supply is connected into a triple-pole (TP) isolating switch which feeds the lift drive power circuits, and individually fuse-protected circuits for the lift car door drive-motor and control circuit transformer(s). A typical control circuit transformer has three secondary windings; 20 V for lift car and landing indicator lamps; 110 V centre-tapped to earth for miscellaneous requirements (such as trapdoor indicating lamps) and 130 V AC, rectified to 110 V DC, for control and interlock circuits. The 240 V single-phase 50 Hz supply is connected into a single-pole and neutral (SP and N) isolating switch feeding an SP and N distribution fuseboard from which separate fused supplies are taken for lift car lighting, control cubicle heating, car-top transformers and lift shaft lighting. The 240 V DC supply is connected into a doublepole (DP) isolating switch, feeding a DP distribution board from which supplies are taken for the audible alarm, lift shaft lighting, fire alarm and flood alarm (if appropriate).
4.3 Motor room equipment Lift motor rooms are located at the top of the shaft for electrically-driven lifts and at the bottom for hydraulic types. They house the supply isolating switches and distribution boards; winding motor/generator; control, interlock and contactor equipment cubicles; lift car and shaft lighting switches; junction boxes for the trailing cables to the lift car, and cable junction boxes for telephone and station alarm circuits. 4.4 Lift drive systems 4.4.1 Electrical
Lift drives are either two-speed or variable-speed. The , former uses motors, as detailed in BSCP 407 [151 supplied at 415 V three-phase 50 Hz through a reversing contactor (raise/lower), a main contactor and a speed change contactor.
Lifts variable-speed drive frequently uses a variaThe oltage (Ward-Leonard) system, in which a 415 V he i v hree-phase 50 Hz squirrel-cage induction motor is iiiedianically coupled to a DC generator which suplift-winding motor electrically. Direct-ona DC star-delta or auto-transformer starting is ern-d for the AC drive motor, as appropriate to the requirements, although the first system is preferred of its simplicity and reliability. Typically, the otor and generator control system is supplied pc m 210 V DC from a transformer/rectifier combinai; tion, f e d from the main 415 V three-phase 50 Hz
cepted' lamp and a series of 'lift position' lamps. Collective control is provided, allowing personnel to board the lift at intermediate floor levels when it is travelling in the selected direction. In addition to the above controls and indications, each landing is equipped with an illuminated panel indicating when the 'fire' or 'flood' control systems are in operation. Flood control systems are only provided when lift shafts could be flooded, as in an underground power station. 4.5.2 Car control facilities
\ typical hydraulic control system comprises a ciratilic ram/cylinder coupled to the lift car, which li pplied with hydraulic fluid through a two-position ;u ;ontrol valve (fast and slow speed) by an electricallyJ r i Ne n pump submerged in an oil tank. The pump motor is a constant-speed squirrel-cage induction motor , u pplied at 415 V three-phase 50 Hz and is started Jirect-on-line, delta-star or by auto-transformer, as he duty demands. The pump is started when 'lift raise' celected; downward movement of the lift is con[roiled by pressure relief valves.
Lift cars are provided with the following controls and indications: 'destination selection' pushbuttons; a series of lamps showing the position and direction of travel; a door opening button; a pushbutton to initiate an audible alarm outside the lift-well and an illuminated panel to indicate when the 'fire' or 'flood' control system is in operation. In addition, cars are equipped with a key-operated selector switch to enable them to be operated by an Attendant. On passenger lifts which have been designed to accommodate stretchers, operation of the 'door opening' button keeps the door open for a preset length of time, to facilitate the removal or loading of the stretcher.
4.4.3 Motor protection
4.5.3 Car lighting
N.1otor circuits are provided with overcurrent, under%oltage, single-phasing, phase failure and phase reversal protection.
Two 600 mm fluorescent fittings are installed in each lift car to provide a general illumination level of 100 lux. The lighting is supplied at 240 V single-phase 50 Hz from the distribution board detailed in Section 4.2 of this chapter, and is controlled by an isolating switch located in the motor room. To safeguard against AC supply failure, each lift car is equipped with self-contained emergency lighting fittings capable of operating for a minimum of one hour following supply failure, in addition to the normal lighting.
4.4.2 Hydraulic
4.4.4
Brakes
Lift car travel brakes are of fail-safe design, being .ipplied mechanically immediately upon disconnection or failure of the supply to the release solenoid. To ,ater for a lift car stopped between floors, the brake fitted with a manual operating mechanism, which dliows the car to be moved to a convenient floor level by hand. Hand release of the brake causes all lift control circuits to be de-energised, allowing the lift to be nio+; ed by use of the manual brake release and winding ;._!ear only.
4.5 Lift car and landing equipment 4.51 Landing control facilities \ complete set of pushbutton controls and indications is provided at each landing. For goods lifts, this comprises a 'call' pushbutton, a 'call accepted' lamp and a series of 'lift position' lamps. Control is arranged so that personnel entering the lift car have complete control until they have disembarked and the doors have closed. For passenger lifts, each landing is equipped with directional call buttons ('up' and `down'), a 'call ac-
4.5.4 Telephone
A wall-mounted telephone is provided in each lift car for emergency use. 4.5.5 Maintenance facilities
The TP isolating switch, connected in the main 415 V three-phase 50 Hz supply to the lift, has three positions; test/off/on. The test position allows control circuits to be tested and adjusted with the 415 V lift-drive power supply isolated. Control cubicle doors are interlocked to prevent access by personnel unless the isolating switch is in the 'off' or 'test' positions. To facilitate maintenance of the lift car, a control selector switch is provided on the car top with three positions; test/normal/off. The test position inhibits control of the lift from any location other than the 819
Mechanical plant electrical services roof top, where up and down control pushbuttons are provided. Operation of the lift is inhibited from all control stations when the 'off' position is selected. Neither the 'fire switch' nor 'flood switch' (if applicable) overrides the car-top control switch, this being necessary to safeguard maintenance staff when the lift is being controlled from the car-top. Provided on the car roof are a 25 V AC socket outlet supplied from a 240 25 V transformer, for use with an inspection lamp, and a 110 V AC socket outlet fed from a 240/110 V transformer to facilitate the use of portable tools.
4.6 Safety devices and systems 4.6.1 Fireman's control system Each lift is provided with a fire switch adjacent to the landing gate designated for fire control purposes, as specified in BS2655 [13]. When the switch is operated, all registered calls are cancelled and the lift car proceeds directly to the designated fire control floor level, where it stops with doors open. Thereafter, the lift can only be operated using the car controls. Indicating panels warning that the fire control system is in operation are provided inside the lift car and on the car-top, adjacent to the maintenance controls detailed in Section 4.5.5 of this chapter. 4.6.2 Flood control system If there is a danger of a lift shaft flooding, a flood control system is provided. A flood control switch is provided adjacent to the designated landing gate located above the maximum flood level, and a flood detection system is installed in the lift shaft. In the event of flooding or the flood control switch being operated, the control system is overridden and the car returned to the designated flood control level where it is parked with doors open. The lift then remains inoperative until the flooded shaft has been drained. When the flood control system is initiated, warning panels are illuminated inside the lift car and on the car-top adjacent to the maintenance controls. However, in the interests of safety, if the lift is under car-top control, downward movement of the lift below the 'flood control' level is inhibited.
Chapter 10 -------lift is stopped and that all control functions are inhibited. To safeguard maintenance personnel driving the lif t from the car-top control station, upward travel i s li mited to within two metres of the shaft top by additional limit switches, functional in that control mod e only, if the normal top-limit switch allows the car t o travel higher. 4.6.4 Lift car emergency hatch
Each lift car is provided with an emergency hatch as required in BS2655 [13]. For a lift provided with a flood control syst em, the hatch is secured with an electromagnetic lock whi c h is released automatically in the event of lift supply failure, when the 'flood control' system is operating or by manual operation of a switch on the car-top. This allows passengers to escape from the lift car by using the escape ladder and doors provided in the lift shaft. 4.6.5 Audible alarm
An audible alarm (Klaxon) is provided outside the liftwell at a suitable location where it can be readily hc,ird when initiated in an emergency by personnel inside the lift car.
4.7 Lift shaft lighting Lighting is provided in the lift shaft which can be switched on manually from the fire control landing and automatically in the event of the fire control system being initiated. To provide adequate lighting for maintenance purposes, selection of the 'test' position on the roof-top selector switch also initiates the lighting. The lighting system comprises tungsten bulkhead fittings fed from an automatic changeover contactor supplied from the 240 V AC and 240 V DC distribution boards, the DC supply being connected in the event of failure of the AC supply. 4.8 Earthing The metal cases of all electrical equipment and metal structures are bonded together and connected to the station earth, an earth continuity conductor being included in the trailing cable system between the lift car and motor room for this purpose.
4.6.3 TrIvel interlocks
5 Gas producing and storage plant
To safeguard personnel, ultimate-limit switches are fitted to prevent overlowering and overwinding. These devices are in addition to the operational limit switches and form a back-up system in the event of failure of the normal control limits. Ultimate-limit switches are hand-reset devices and are connected in at least two of the three phases of the lift drive 415 V supply and in the control circuit supply to ensure that the
5.1 Introduction This section covers the electrical aspects of gas producing and storage plant which form an essential part of modern power stations. The types of plant described are as follows:
820
• Hydrogen production by the electrolytic cell process.
• Gas producing and storage plant Hydrogen production b y methanol chemical •
1Ction
r
.
• \ierhane production. • 'ci[rogeri storage. Carbon dioxide storage. •
,
o f [he Ntential hazard to personnel and plant, croduction and storage plants are located away . the main building complex. 011l principal uses of the various gases are given Th e
E Hlogen Sieiharle
main generator cooling mixed with carbon dioxide coolant gas to minimise graphite corrosion in gas-cooled reactors used for sealing feedheaters, condensers and similar plant, also reactor circuits during shutdown.
irbon dioxide
reactor coolant gas and generator purging.
lkin considerations which are common to all gas rroduction and storage plants are described in the 1 lowing sub-sections. rhe choice of hydrogen generation plant is dictated h ■ economic considerations. Costs associated with the .:1c,trolytic cell process are generally higher than those an equivalent methanol chemical reaction system :II terms of capital and running costs. Electrical energy consumption of the electrolytic cell 3 process is in the order of 4 kWh to generate 1 m of '1 0rogen per hour compared with 1 kWh of the methanol-based system. Plant costs of the two systems ze compatible but civil costs associated with the elec:rol ■ tic cell process are generally higher. The cost of il o:hasing and storing methanol is also taken into
VIvanced gas cooled reactors (AGRs) require large
Liantities of oxygen for coolant gas regeneration purSince the electrolytic cell process produces large ti.Inuties of oxygen as a by-product, this process is
driers, control cubicles and instrumentation. Oil-filled transformers are located outdoors to minimise the fire risk. When an electrical equipment room adjoins a hazardous area, extreme care is taken to ensure that all penetrations through the dividing wall are adequately sealed. Hazardous areas are classified as Zones 0, 1 or 2, as defined in BS5345 [5] (see Section 2.4.2 of this chapter), and all electrical equipment for use therein is certified by British Approvals Service for Electrical
Equipment in Flammable Atmospheres (BASEEFA) in accordance with that standard. Installations comply with BASEEFA certification standards SFA3012 — Intrinsic safety; SFA3004 — Shunt diode safety barriers and SFA3008 — Increased safety. Electrical connections between a non-hazardous area and a Zone I area (in which an explosive gas/air mixture is likely to occur in normal operation) are made through a barrier cubicle. The barrier cubicle accommodates equipment which constitutes an electrical interface between the 'safe' signals necessary for equipment in the hazardous area and the signals necessary for plant in the non-hazardous area, thereby allowing the use of non-specialist equipment in the latter environment. A back-up safety protection system is provided to ensure that in the event of plant, control or protection malfunction, the plant is tripped before an unsafe condition can arise in a hazardous area designated Zone 1. In explosive or hazardous gas environments, the use of aluminium is avoided since it has been demonstrated that, under certain abnormal conditions, the i mpact of rusty iron and aluminium can create an ignition source. Whilst the risk is low, the use of aluminium cables and aluminium paint is avoided since suitable alternatives are readily available. 5.2.2 Lightning protection
When the plant does not fall within the lightning protection zone of another building, a horizontal lightning protection system is provided in accordance with BSCP326 [16]. Lightning protection is discussed in Chapter 6, Cabling.
twured for hydrogen generation at AGR power
s . ,Itions. At other types of power stations, by-products
OF no significance. 5.2
5.2.1 In the
G4nerai requirements Safety assurance and standards
interests of personnel safety, ease of mainte'wce and minimisation of equipment costs, as much ..!,:,trical equipment as possible is housed in electrical i'glitPment rooms, designated as 'safe areas'. Equipment 0 . 0ms house transformer/rectifier units, switchgear, rotor control gear, air compressors, air receivers and
-
5.2.3 Motors in hazardous areas
In addition to the requirements for motors previously referred to in Section 2.2 of this chapter, those in hazardous areas comply with the following British Standards. Motors for use in areas designated Zone I (see Section 2.4.2 of this chapter) comply with the requirements of BS4683 [4], Part 4, appropriate to protection type 'e'. Maximum surface temperature is limited in accordance with Class T3. Motors for use in areas designated Zone 2 are provided either to the same standard as for Zone 1, or to BS5000 [I], Part 16, Type N. 821
PP Mechanical plant electrical services 5.2.4 Switchgear and contactor controlgear Switchgear and contactor controlgear is located in non-hazardous areas and is provided to the same standards and specifications as that elsewhere in the power station (see Section 2.6 of this chapter). 5.2.5 Control and instrumentation equipment
Chapter 10 and short-circuit conditions. Rectifier equipme nt i s classified as electronic equipment and must meet the requirements of EES (1980) [6], referred to in Sectio n 2.5 of this chapter. DC smoothing is provided to limit ripple content to 5% of the mean value under any of the supply varia, tions detailed in Section 2.1,2 of this chapter.
Control and instrumentation equipment is located in non-hazardous areas and is provided to the same standards and specifications as that elsewhere in the power station, in accordance with CEGB specification US/76/10 [17].
Protection The basic protection requirements of transformer/ rectifier units are listed below and shown on Fig 10.9 ; • A rectifier AC overload relay arranged to trip th HV supply.
e
5.2.6 Transformer/rectifier equipment
• A rectifier DC overload relay arranged to trip th HV supply.
e
Transformer/rectifier equipment are located in nonhazardous areas and are provided to the same standards and specification as that elsewhere in the power station in accordance with BS417 [181, BS171 [19] and British Electricity Board Standard BEBST2 Part 5 [20]. An outline of the design requirements is given below. Figure 10.9 shows a typical transformer/rectifier equipment schematic diagram.
Transformers and chokes Rectifier transformers and chokes are naturally aircooled: Class F to BS2757 [21] insulation is used but winding temperatures are limited to Class B BS2757 [21], in the interests of long life and reliability. To allow compensation for distribution voltage variations, transformer primary windings are provided with off-load, bolted-link taps, giving ±5o on the nominal voltage. An earthed screen is provided between primary and secondary windings to protect rectifier equipment in the event of a winding fault developing in the transformer. Delta-connected transformer primary windings and double-star secondary rectifier connections are used to minimise ripple in the DC output and heating of electrolytic cells. Rectifiers Full-wave bridge rectifiers are used, employing either silicon junction diodes or thyristors. Because of the arduous operating conditions in a power station and the need for maximum reliability and life, individual diodes or thyristors are rated at twice the load current and the equipment designed for a cubicle ambient air temperature of 55 ° C. Spare diode capacity is built into each rectifier bridge arm. Individual diode/thyristor fuses are fitted for protection in the event of diode/thyristor failure. To assist maintenance, indicating lights are provided to identify the rectifier arm in which failure has occurred. Rectifiers are protected against voltage spikes by surge-suppression circuits. High speed semiconductor rectifier fuses are fitted to protect against overload 822
• Rectifier diode/thyristor fuses, with a monitoring system designed to trip the HV supply. • Surge-suppression equipment fuses, with a monitoring system arranged to trip the HV supply. 5.2.7 Frost protection All pipes and storage vessels which may be subjected to frost and may consequently jeopardise the safe and efficient operation of the plant are equipped with trace heating or immersion heaters, as appropriate. Anti-frost equipment is controlled automatically by temperature sensors, either pocket thermostats or thermocouples, to maintain the temperature of the equipment around 5 ° C. Control circuits operate at 110 V AC. Thermostats located in hazardous Zone 1 areas are BASEEFA-certified and form part of an intrinsicallysafe circuit. Trace heating in the form of tape is wrapped around pipework, each section or circuit being separately protected by fuses and supplied at 110 V AC from a 415/110 V transformer. The 110 V secondary winding is centre-tapped to earth to limit the voltage to earth to 55 V in the interest of personnel safety, and an earthed screen is provided between the two windings to prevent the transfer of excessive voltages from primary to secondary. Trace heating tapes are of two basic types, resistance and self-regulating, and have a uniform thermal rating per unit length. Resistance-type trace heating tape comprises two insulated resistance elements running parallel to each other for the length of the tape and interconnected at one end to form a loop. A thermostatically controlled electrical supply to the loop regulates the heat output. The maximum length of a tape section is limited by its loop resistance and by the capacity of the supply. Self-regulating trace heating tape comprises two conductors running parallel to each other for the length of the tape and separated by a conductive 'core' ma terial, the conductance of which varies in response to changes in temperature. The heat output is there fore self-regulating and thermostats are not necessarY.
Gas producing and storage plant
COOLING FAN FAIL RELAY 415V,3 PHASE ,50 Hz
V
'
,17
4.1S
1 0
'
COOL ING AN MO
FC)F4
MAIN CIRCUIT BREAKER TRIP CIRCUIT
OVERCURRENT PRO TEC TION
AC OVERLOAD RELAY
DEL TA-STAR/STAR TRANSFORMER
a
AC SUPPRESSION VARISTOR FUSE FAIL RELAY
THY RISTOR FUSE FAIL RELAY
0--
THY RISTOR OVERTEMPERATURE RELAY
DC SUPPRESSION VAR ISTOR FUSE FAIL RELAY
PULSL AMPL IF ri R
DC SUPPRESSION VAR ISTOR
DC CIRCUIT BREAKER
7
DC VE
7
DISCONNECTOR
DC - VE
FIG. 10.9 Typical transformer/rectifier equipment — simplified circuit diagram 823
PP' Mechanical plant electrical services I mmersion heaters are provided in storage vessels and are supplied at 240 V AC when their rating is low . enough to be controlled directly by thermostats. For higher ratings, a 415 V three-phase 50 Hz supply is used and controlled through a contactor by a temperature-sensing device. Each storage tank is fitted with a thermostat to control the temperature over the desired band. When overheating, such as might occur in the event of failure 01 a thermostat, could prove dangerous, an extra 'safety' thermostat set to operate at a higher temperature than the control thermostat is connected in series with the control thermostat. The safety thermostat is manually reset. Temperature sensors and immersion heaters are both designed to be removable for maintenance purposes, without the storage tank being drained. Alarm thermostats are provided to warn the operator if the heating system fails to maintain the fluid above the minimum temperature. 5.2.8 Earthing and static protection In hazardous areas, it is imperative that all equipment is bonded together and earthed in order to prevent the build-up of static or potential differences between items of plant or equipment, both of which create risk of a spark and hence ignition. The 415 V switchgear earth-bar is connected to the station earth. All metal vessels, pipework and nonconducting metalwork, with the exception of electrolytic cells, are bonded together and connected to the s witchgear earth-bar with 70 mm 2 copper PVC-insulated and sheathed cable. The metal enclosures of all electrical equipment are treated similarly. Continuitybonding conductors are connected across all uninsulated pipework joints of bolted or screwed construction. Precautions are taken to prevent the transfer of potentials along pipework into hazardous areas and to ensure that circulating currents cannot occur in pipework and supporting structures due to the high current levels in gas generating electrolytic cells. To this end, electrolytic cells are mounted on insulated supports and all metallic pipework connected to the cells has insulated flanged joints in the vicinity of the cell. Each low pressure delivery main into gas storage vessels is mounted on insulated supports and equipped with an insulated joint outside the storage area. The insulated joints and supports must have a minimum insulation resistance of 2 Mf2 at 500 V DC.
5.3 Hydrogen producing plant — electrolytic cell process 5.3.1 General description of plant The electrolytic cell process for the production of hydrogen comprises banks of cells, using a solution of caustic soda and water, or potash and water, as an electrolyte. A low voltage DC supply from a trans824
Chapter 10 former/rectifier unit to the cells causes hydrogen t o be produced at the cathode and oxygen at the anode. Since the rate of production is directly proportional to the DC current, hydrogen production is regulated by rectifier control. Electrolyte level is maintained by a demineralised water make-up system. Hydrogen from the cells passes via a gasholder, at a maximum pressure of 12 mbar, to compressor s operating at high discharge pressure (25 to 30 bar) a n d through driers and filters to the HP storage ve sse l . For distribution, hydrogen pressure is reduced to 10 bar. Oxygen is vented to atmosphere. A typical syst em diagram is shown in Fig 10.10. The disposition of equipment within the hydrogen plant compound is illustrated in Fig 10.11. In general terms, the plant layout consists of an outdoor storage area, in which the HP and LP storage vessels are situated and a building containing the compressor, electrolytic cell and electrical equipment coon -is. Hydrogen compressors, filters and driers are housed in the compressor room; switchgear, transformer/rectifier equipment and the gas production control panel are housed in the electrical equipment room and he hydrogen producing cells in the cell room. 5.3.2 Classification of plant areas The classification of the various areas, as defined in BS5345 [5], is as follows and electrical equipment is provided accordingly (see Section 5.2.1 of this chapter): • Electrolytic cell room — Zone 1. • Hydrogen compressor room — Zone 1. • Storage area: (a) Within 1 m of storage vessels or directly above them — Zone 1. (b) Within 3 m of storage vessels excluding (a) — Zone 2. (c) Remainder — non-hazardous. • Electrical equipment room — non-hazardous. 5.3.3 Electrical, control and instrumentation equipment DC connections and busbars Connections between the electrolytic cells and the rectifier equipment consist of hard-drawn, high conductivity copper busbars complying with BS159 [22] and BSI58 [23] or PVC in4 sulated and sheathed copper cables to BS6346 [2 1. Busbars within the hazardous environment of the cell room are insulated with anti-static PVC. From the cell room, the connections pass through wall bushings into the electrical equipment room where, if they are busbars, they are protected by a wire-mesh screen to prevent accidental contact. The wall bushings are gastight to ensure that hydrogen is prevented from entering the electrical equipment room under all circumstances.
Gas producing and storage plant
HYDROGEN VENT
HYDROGEN HYDRAULLC
REL EF 'MOE
H ----
-
,v3A:AELP I
,-,
DROGEN
CON7q0L
PPESSURE GAS H.OL:,'ER
TT 01cr
f
— TI
b41-
1 ES SURE STORAGE ■ ESSELS
HIGH
RECIRCULATION
11.111—
11.41— A
104—
MO-
cr
FILTAS
DEOXYGENATOR :IF REOLJIRED)
FLTERS
111 I
a
1-•.; gSTR S
25.10 tar EXCESS FLOW
HvDROGEN TO CONTROL PANEL
F[0. 10.10 Hydrogen generation plant — electrolytic cell process — system diagram
installation and testing
Cabling practice is the
..!:c a,
hat adopted elsewhere in the power station, from [hat associated with electrical equipment •..;:ed in the hazardous areas referred to in Section 2 ot his chapter, where it is required to be cornNe the appropriate safety requirements. Par-
.
—
; Li attention is paid to the earthing of screens and now-5 and the glanding and termination of cables
:Litiipment, Installation and testing complies with k.' ,..ommendations of BSCP1003 [25] and BS5345 IL:rrw.unit cubicle
A barrier-unit cubicle is located •1 ie electrical equipment room and accommodates r unnsically safe relays and shunt-diode safety bar. necessary for the interconnection of electrical •• • Tinent in the hazardous areas with power sources .: J equipment in the electrical equipment room. -
jrling notices and gas detection
- oh:biting -
Warning notices smoking and naked lights are provided at
all entrances to hazardous areas and are permanently illuminated from a 110 V AC/DC supply. Gas detectors, operated from the same 110 V AC/ DC supply as the warning notices, are installed in all rooms, including the non-hazardous electrical equipment room, and initiate audible and visual alarms at the entrance to the specific area where gas has been detected. Back up protection
As mentioned in Section 5.2.1 of this chapter, the overall protection of the plant is assured by the provision of a back-up protection scheme. The scheme is arranged to trip the circuitbreaker of the incoming supply to the 415 V switchboard in the event of a contactor failing to open after initiation of a trip. Devices provided to initiate tripping of a contactor are either fitted with duplicate contacts or are duplicated to operate into the back-up protection scheme. The plant control and back-up safety protection systems function independently to ensure that plant -
825
Mechanical plant electrical services
Chapter 10
ELECTRICAL ROOM
CELL ROOM
TRANSFORMER/ RECTIFIER
CELLS
11
COMPRESSED AIR PLANT
1
0
COMPRESSOR ROOM
COMPRESSORS =I
0
00 H . P. VESSELS
EMERGENCY GATE
SECURITY FENCE
Ha. 10.11 Hydrogen generation plant — layout of compound and buildings
safety is not jeopardised by control system faults. The back-up safety system is arranged so that, in the event of any plant parameter exceeding the normal control range such that it could give rise to a potential hazard, the circuit-breaker is tripped, rendering the plant safe. Gas production control panel The gas production control panel is located in the electrical equipment room and forms the control centre of the plant. Control of 826
the hydrogen plant is normally automatic, but manual control and test facilities are provided. Incorporated in the control panel are the following facilities: (a) A mimic diagram indicating the state of plant. (b) Indicating and recording instruments for hydrogen pressure, temperature, purity, dryness and other data necessary for the operation and monitoring of the plant. (c) Rectifier controls and indicators.
■W""
-Gas producing and storage plant en compressor controls and instruments, for Hy d rog (J) each compressor, including duty selection switches (duty/auto standby/manual standby). ) Control and instrumentation (C and I) air compressor controls and instruments, similar to (d) above nnunciator panel incorporating 'alarm aca 'reset' and 'test buttons, an audible alarm, ,: epr', and repeat alarm contacts to bring up alarms in the Central Control Room of the power station. ‘larm
Ihe oeneral control philosophy is 'failure-to-safety'.
5.4 Hydrogen producing plant — methanol chemical reaction
Electropneumatic converter equipment
5.4.1 General description of plant
Due to the clammable nature of hydrogen, all automatic valves in the gas system are pneumatically controlled through clectropneumatic converter equipment located in a non-hazardous area, normally the electrical equipment room. The equipment operates from the C and I air which has a nominal working pressure of 7 bar. Hydrogen compressor control Three compressors are prosided, each capable of handling the total cell proJuction, to ensure that adequate standby capacity is ,na il able when one unit is off-stream for maintenance. Flie compressor system automatically maintains hydrogen pressure in the HP receivers at a maximum pressure of 31 bar and incorporates safeguards against ;I l e compressors running when the LP reservoir is less than 10To full. Normally two compressors are selected to `duty' and one to 'standby'. The number of compressors running is selected automatically according to the level hydrogen in the LP storage vessel. An emergency stop-switch controlling all three compressors, of a type appropriate to the Zone 2 classiCication of the area, is provided in the compressor
room.
manual control facility is provided at the 415 V itch board C and 1 air compressor control
Two compressors
,irc provided, each 100 ,7o-rated, one being selected to
'duty' and one to 'standby'. Their operation is normally Jtoomatic, being governed by pressure switches on the storage vessel. A manual control facility is provided at the 415 V sssitchboard. Rectifier control
The quantity of hydrogen produced the cells is controlled by varying the rectifier output i.urrent. This is normally automatic, but a manual ,orarol facility is provided. The rectifier output is aried by switching the AC rectifier supply. Under livomatic control, pressure switches in the HP hydrogm network are used to vary hydrogen production and so to maintain pressure in the pipework and stor,
age vessel between 25 and 30 bar. They shut down production in event of HP storage vessel pressure exceeding 31 bar. In the event of the LP storage vessel becoming more than 95% full, the rectifier AC supply is isolated. Automatic voltage control is incorporated to maintain a constant DC current output under any of the supply system variations detailed in Section 2.1.2 of this chapter.
An alternative process to that described in Section 5.3 of this chapter, uses a mixture of methanol and water (typically 64 0/o methanol and 36°70 water by weight) for the production of hydrogen. A typical system diagram is shown in Fig 10.12. The methanol/water mixture is pumped from a storage tank, through a heat exchanger, to a preheater which vaporises it. The rate of hydrogen production is controlled by switching the AC supply to the preheater, thereby controlling the rate of fuel vaporisation. The vapour then passes over a catalyst which breaks it down to a gas, the main constituents of which are hydrogen and carbon dioxide. This hydrogen-rich gas then passes into a diffusion chamber, where the hydrogen is separated and fed to a gas holder. Waste carbon dioxide is vented to atmosphere from the diffuser. Hydrogen from the gas holder is passed to compressors operating at high discharge pressure (25 to 30 bar) and then through driers and filters to the HP storage vessel. For distribution, hydrogen pressure is reduced to 10 bar. The disposition of equipment within the hydrogen plant is similar to that shown for the electrolytic cell process in Fig 10.11, and consists of an outdoor storage area and a building incorporating compressor, methanol generator and electrical equipment rooms. 5.4.2 Classification of plant areas
The classification of the various areas, as defined in BS5345 [5], is as follows and the electrical equipment is provided to suit (see Section 5.2.1 of this chapter): • Methanol gas producer room — Zone 1. • Hydrogen compressor room — Zone I. • Storage area: (a) Within 1 m of methanol and hydrogen storage vessels or directly above them — Zone 1. (b) Within 3 m of above storage vessels — Zone 2. (c) Remainder — non-hazardous. • Electrical equipment room — non-hazardous. 827
C hap te r
VAPOUFUSE
VAPOiJ RISE fi
Mechanical plant electrical services
WASTE GAS DISCHARGE
L.P. GAS HOLDER
DEOXYGENATOR (IF REQUIRED)
H
P. STORAGE VESSELS
r'LN
Y
FILTERS
FILTERS
TO DISTRIBUTION (25-30 bar)
FIG. 10.12
828
DRIERS
Hydrogen generation plant — methanol chemical reaction system
PUMPS
io
Gas producing and storage plant 5.4.3 Electrical,
control and instrumentation
ment Nlany similarities exist between this plant ,11 described in Section 5.3 of this chapter. En L i' , 1 1.1, cabling, barrier cubicle, warning notices ;. Jotection, back-up protection, electropneumaquipment, hydrogen compressor control r(er e air L.7.k.-mn pressor control, all fall into this c and
equip
connections and busbars Connections between s iteligear in the electrical equipment room • ,h e ge neration plant in the methanol gas producer omprise either non-static PVC insulated, hard high conductivity copper busbars complying S158 1231 and BS159 122] or PVC-insulated and B copper cables to BS6346 [24]. Busbars in ;; hazardous environment are insulated with anti•i ; pVC. These connections pass through bushings hc separating wall into the electrical equipment I here, if they are busbars, they are enclosed by w mesh screen to prevent accidental contact. The • are gas-tight to ensure that hydrogen is ,..nted from entering the electrical equipment room ; Jcr all circumstances. production control panel The gas production [1!rol panel is located in the electrical equipment and is the focal point for control of the hydrogen 2:,mr. Accommodated in the control panel are the • , I1 0‘king facilities for automatic and manual control: ,
• \ mimic diagram indicating the state of the plant. • indicating and recording instruments for hydrogen rrosure; methanol supply purity; hydrogen tempera:tire, dryness and purity; and other data necessary or the operation and monitoring of the plant. • I ! Orogen generation controls. • il),Iroe.en compressor controls and instruments. •
(.
and I air compressor controls and instruments.
• \ l am annunciator panel, incorporating 'alarm acp:', 'reset' and 'lamp test' pushbuttons, an audible aLarrn and alarm contacts used to bring up alarms :0 he Central Control Room of the power station. general control philosophy is 'failure-to-safety'. it.drcwn generation control Automatic and manual iirrol of the methanol generator is provided, the 'ruler being designed to maintain the selected hydroProduction rate, irrespective of variations in system • "d dmbient conditions. The rate of gas production ..antrolled by switching or varying the voltage of :lc preheater AC supply to maintain gas pressure in 1-1 1' pipeline and storage vessel between 25 and bar. Production is stopped if the gas pressure rises •
,
to 31 bar or if the LP gas holder is greater than 95 07o full. Manual control facilities comprise 'auto/manual' control selection, production 'on/off' and 'raise/lower' controls. Preheater supply A contactor-controlled 415 V threephase four-wire supply is provided to the preheater, the individual elements of which are connected for 240 V single-phase operation. Overload protection is provided on the 415 V supply and arranged to trip the supply contactor and raise an alarm. Protection devices trip the heater supply when the heater temperature exceeds approximately 570 ° C and restore it automatically when the temperature falls to a safe level. This prevents the gas generator from overpressurising.
5.5 Methane production plant 5.5.1 General description of plant
Methane (CH4) is produced by the catalysed reaction of carbon dioxide (CO2) and hydrogen (H2). Carbon dioxide is drawn from the CO2 storage tanks and hydrogen from the LP gasholder. Hydrogen is supplied to the methanation plant via an LP compressor and mixer, the hydrogen and carbon dioxide mixing at sufficient pressure to drive it through the methanation process plant. Methanation takes place within a catalyst vessel, the methane produced being fed via compressors and separators to an HP storage vessel. Methanation occurs in two stages within the tubes of the reaction vessel over a bed of catalyst packed inside the tubes. From the first stage reaction vessel, the gas produced passes via the tube side of a recuperative heat exchanger into the first stage condenser which removes water produced in the reaction. The gas is then passed through the shell side of the recuperative heat exchanger to raise its temperature prior to entry into the second stage reaction vessel. Gas temperature is controlled by adjusting the volume of gas returned through the heat exchanger, using the inlet regulating and by-pass valves. The heated gas then passes through the second stage reaction vessel and through the second-stage condenser, where the water produced by the reaction is again removed. From there, the methane gas is compressed and fed to the HP storage vessel at a pressure in the order of 44 bar. The rate of methane production is controlled either automatically or manually by varying the supply of hydrogen and carbon dioxide from their respective storage vessels. Once started, the process within the reaction vessels generates sufficient heat for it to be self-sustaining. However, to start the reaction, the first stage vessel 829
VP' Mechanical plant electrical services is heated to operating temperature by electrical fan heaters. A typical system diagram is shown in Fig 10.13. Methane production plants include hydrogen production and storage facilities as outlined in Sections 5.3 and 5.4 of this chapter.
Chapter 10 is further reduced outside the storage plant for final distribution. Make-up water supplies to electric heat storage vaporisers are trace heated to prevent freezing. A typical storage-compound layout is shown i n Fig 10.14 and a bulk storage system in Fig 10.15. 5.6.2 Electrical requirements
5.5.2 Classification of plant areas The classification of the areas of the plant, as defined in BS5345 [5], is as follows and electrical equipment is provided accordingly (see Section 5.2.1 of this chapter):
Electrical requirements are limited to supplies for va_ poriser heater control cabinets, heaters, motorised valves, solenoid valves, trace heating and lighting. 415 V three-phase 50 Hz is provided for the purpose.
• Electrolytic cell room — Zone I. • Hydrogen compressor room — Zone 1. • Methane reactor room — Zone 1. • Methane compressor room — Zone I. • Storage area: (a) Within 1 m of hydrogen storage vessel and above it — Zone I (b) Within 3 m of hydrogen storage vessel excluding (a) — Zone 2. (c) Remainder — non-hazardous. • Electrical equipment room — non-hazardous. 5.5.3 Electrical, control and instrumentation equipment The hazards associated with the production and handling of hydrogen and methane are similar and the general requirements in respect of electrical equipment are as detailed for hydrogen plant in Section 5.3 of this chapter. Central control of the methane production process is provided at a gas production control panel located in the electrical equipment room, automatic and manual control facilities being provided.
5.6 Nitrogen storage plant 5.6.1 General description of plant Liquid nitrogen is stored in a vacuum-insulated vessel. A bank of vaporisers, typically four, converts the liquid into nitrogen gas for distribution. The vaporisers may be any one of four types: electrical heat storage, ambient air fan-assisted, ambient air natural-draught, or steam (when auxiliary steam is available). The choice of vaporiser depends upon nitrogen production rate, that of power stations usually dictating the use of electrical or steam heated types because of their greater capacity and compact size. Gas pressure at the exit from the vaporisers is regulated by control valves within the range 7 to 17 bar for distribution purposes. Distribution is isolated if gas pressure exceeds 17 bar or if its temperature falls below 10 ° C. Gas pressure
5.7 Carbon dioxide storage plant 5.7.1 General description of plant Liquid carbon dioxide is delivered by road tanker and stored in a vacuum-insulated vessel. A fully automatic refrigeration system is provided which maintains the vessel pressure at 20 bar at – 17 ° C. Vaporisers convert the liquid into carbon dioxide gas for distribution. Vaporisers may be any one of four type,; electrical heat storage, ambient air fan-assisted, ambieN air natural-draught or steam (when auxiliary steam is available). The choice of vaporiser depends upon car. bon dioxide production rate, that of power stations usually dictating the use of electrical or steam heated types because of their greater capacity and compact size. Gas distribution pressure is nominally 19 bar. To prevent the passage of liquid carbon dioxide through the vaporisers and into the distribution system in the event of a fault, the gas temperature at the vaporiser outlet is monitored. If the gas temperature falls to – 10 ° C, a control valve isolates the feeder to the distribution system. A typical storage compound layout for generator purging is shown in Fig 10.16 and bulk storage system in Fig 10.17. Nuclear power stations need a larger storage capacity and a greater number of storage vessels and vaporisers, but the basic requirements are the same as for fossil-fired stations. 5.7.2 Electrical requirements Electrical requirements are limited to supplies for vaporiser heater control cabinets, heaters, refrigeration units, motorised valves, solenoid valves and lighting. 415 V three-phase 50 Hz is provided for the purpose.
6 CW electrochlorination plant (sodium hypochlorite production and storage) 6.1 General description of plant Sodium hypochlorite is produced for the treatment of cooling water (CW). Sea water is pumped through strainers to banks of electrochlorination cells. Thyristor
CW Electrochlorination plant (sodium hypochlorite production and storage)
CARBON DIOXIDE STORAGE TANK
DBOGEN G AS ■ 101_ DE P
L.
H2
CO2
MIXER 2
METHANATION VESSELS 2ND STAGE REACTION VESSEL
isT STAGE REACTfON VESSEL
C1-14
1ST STAGE REACTION VESSEL
RECUPERATIVE NEAT EXCHANGERS
2ND STAGE REACTION VESSEL
CH4
CONDENSERS
111
COMPRESSORS (3 x 100%)
SEPARATORS
TO METHANE R.P. STORAGE VESSEL
10.13 Methane (CH4) production plant — system diagram 831
Mechanical plant electrical services
Chapter 11)
I
TEMPERATURE CONTROL VALVE
2 PRESSURE CONTROL VALVE 3 ISOLATING VALVE 4 REUEE VALVE HEATER CONTROLS
TO BUS
1°71. 7 21 3600
TOO
1 830
1525
3
1
830
THERMAL STORAGE VAPORISERS
3350
‹,)
STORAGE VESSEL ALL DIMENSIONS IN mm
FIG.
10.14 Nitrogen storage plant layout
controlled rectifier units provide LV variable voltage DC supplies to the cells, thereby controlling the rate of production of sodium hypochlorite by electrolysis within the cells. A by-product of the process is hydrogen, which is of inadequate purity for use in a power station and has, therefore, to be exhausted in a controlled and safe manner. A solution of sodium hypochlorite, hydrogen and sea water leaves the cells and is fed to a hydrogen release tank, which exhausts the hydrogen to atmosphere. The hydrogen-free sodium hypochlorite solution then passes to a storage tank. Sodium hypochlorite is pumped from the storage tank to the dosing points in the water treatment plant. A system diagram for a power station site is shown in Fig 10.18. The disposition of equipment within a typical CW electrochlorination plant is illustrated in Fig 10.19. Electrical equipment rooms housing 415 V switchgear, transformer/rectifier units, control/mimic panel and control air pumps are situated adjacent to the electrochlorination cell room. Outside the building is a storage area in which the sodium hypochlorite storage tanks, sodium hypochlorite distribution pumps and hydrogen release tanks are situated, the latter being above the 832
storage tanks and at a high level to ensure the safe discharge of hydrogen. 6.2 Classification of plant areas The classification of areas, as defined in BS5345 [5], is as follows, electrical equipment within those defined areas being provided accordingly (see Section 5.2.1 of this chapter). • Electrochlorination-cell room — Zone 1. • The area directly above the hydrogen release tank — Zone 1. • Within 2 m of the hydrogen release tank — Zone 2. • Electrical equipment room(s) — non-hazardous. 6.3 Electrical, control and instrumentation equipment 6.3.1 General
Many similarities exist between the electrical require ments of this plant and of the hydrogen production
-
• CW Electrochlorination plant (sodium hypochlorite production and storage)
111 i
WATER PATE VA PO B IS EA
t3-1 FE.kwE RA T,RE
• •-
■
•1
t
•,p, ma
, AL rE
2 3m
+APOLAR RELEASE
1:4
,
IlliMi
35
ll
S.
FRONT ELEVATION
TANK BUILD-UP PRESSURE REGULATOR
VAPOUR PRESSURE CONTROL VALVE
TURBINE HOUSE WALL
CO2 GAS TO S - C.P.GE
GENERATORS
TANK
• DI ▪
-•• _—
oqEssuRE acs ■ hrGcc.L
DRAWAL
1 , 1 6. 10.15 Nitrogen storage system
Jes,:ribed in Section 5.3.3 of this chapter. Re111CIIIS
which are similar for both are described
:c following sections: DC connections and busbars,
harrier unit cubicle, warning notices and gas back - up protection, electropneumatic conequipment, and C and I air compressor control. 6 12
Production control panel
• production control panel is located in the electrical .. pinent room and constitutes the control centre for production and storage of sodium hypochlorite or its distribution for water treatment purposes. \„. , iii modated in I he control panel are the following for automatic and manual control:
• ■
mimic diagram indicating the state of the plant.
• fransformer/rectifier controls and indicators.
• '■:a water feed pump, filter controls and indicators. • 1.1 e ,:trochlorinator controls.
•
hypochlorite storage tank level indication.
• fl
hypochlorite dosing pump, flow valve
..ontrok and indicators.
• t. and I air compressor controls and indicators.
• \azci- treatment (sodium hypochlorite dosing) control. • \uzo/manual' selection and 'open/close' controls and indicators for all control valves. •
PLAN
FIG. 10.16 Carbon dioxide storage plant layout
• Alarm annunciator panel, incorporating 'alarm accept', 'reset' and 'test' buttons, an audible alarm and repeat alarm contacts to initiate alarms in the Central Control Room. The control system is designed for automatic control of the plant under normal operational condition, with the facility for manual control, if necessary. Overall control of the system is via a programmable logic controller (PLC) housed in the control panel. 833
Mechanical plant electrical services
Chapter io
;191 mAL,E FOR roe, NG A yo T EMPEPAYuRE
PRESSOXE -.1xu ,GE LIQUIG
,
1_0 N0 LINE
`4 4POuR BrLLANCE LiNE
L
,E
290 tv BYPASS
POE GS, 9E 34•-IUE m r, ALARM SON TAC 7 S
C4
4
2)0 bar
-
1f
LOCKE° CLGSES
E PERAT UPE SENSING POirr
10 W JAPORISER 1
292b
\
290 oar
P4 4.4.404:1■11■4.
,
III ALS, ,,LpORISER 2
I
I
SOL E N0 , 0 'JRE.XTE0 LOW 7 E 1 IRE RXTURE SNU .-DFP • Xr.VE
CON TOOL BOX
T ON 'L.., I
VAPOUR DRAVY-OPF UNE PRESSURE bYvISCN FOR REF fl , GERA TION CONTROL
C ,, PeON C , OxIDE 3ENEaAtoRGAs ..S ONYROS. PANELS
CONTEN IS GAGGE b TONNE STORAGE VESSEL
FIG. 10.17 Carbon dioxide storage system
6.3.3 Sea water feed pumps and strainers control
The scheme shown in Fig 10.18 has three 415 V threephase 50 Hz sea water feed pumps each capable of delivering half of the total teedwater flow required. Two of the three pumps are selected to 'duty' and one to 'standby'. Loss of a duty pump automatically causes the standby pump to start. Two motorised sea water strainers are provided, each having sufficient capacity to handle the full plant output.
Automatic operation of the dosing system is con. trolled by the production control panel logic system, the number of pumps started being determined by the number of hypochlorite generators needed to satisfy chlorination requirements. Hypochlorite flow from the dosing pumps is auto. matically regulated by two motorised valves installed in the pump outlets. 6.3.7 Electrical distribution
6.3.4 Transformer/rectifier controls
The scheme shown in Fig 10.18 has eight transformer/ rectifier equipment, each supplying DC current to its associated electrochlorinator. The transformer/rectifier units can be selected for automatic or manual control either individually or as a group, thereby ensuring maximum control flexibility. 6.3.5 Sodium hypochlorite storage
Production of sodium hypochlorite is governed by the level in the storage tanks, leading to shut down if the maximum level is reached. Similarly, a low level will shut down the dosing pumps. 6.3.6 Dosing pump controls
The scheme shown in Fig 10.18 has four 415 V threephase 50 Hz dosing pumps, each capable of delivering one-third of the maximum dosing rate. A 'three out of four' duty selection scheme is provided; the fourth pump is on standby and starts automatically upon failure of one of the duty pumps when automatic control is selected. Manual control of each pump can be selected, if required, thereby ensuring maximum flexibility of operation. 834
The majority of supplies to the plant drive-motors are 415 V three-phase 50 Hz and are derived from two contactor boards, each board being supplied separately. An interconnector is provided between the two boards. This ensures security of supply with the maximum operating flexibility. Multiple drives, such as transformer/rectifier equipment and dosing pumps, are spread over the two boards to minimise the effect on plant operation of the loss of one board due to supply failure. The electrochlorinators present the largest individual loads, each being in the order of 750 kW, and are supplied at 3.3 kV three-phase 50 Hz by circuit-breakers on two switchboards. Hypochlorite dosing pumps, typically 55 kW, sea water feed pumps and ventilation fans are supplied by electrically-held contactors on the 415 V boards. 7 Water treatment plant
7.1 Description of plant The design of water treatment plant varies according , to the quality of raw water which may be sea, river lake or towns water; the first two sources are the more
Water treatment plant
FiUSHiNG WATER r1EAD TANK
'NAE
•,5
SPRAYS
TRANSFORMER RECTIFIER ,
B,1,= ■<
-
-
>4
1
cl$
-
PRODUCT:ON CONTROL PANEL
01•-{EH - • TRAN+SII:AROI.AER RECTIFIER
D.{
1 0 PONT'S OF APPLICAIIION
,■•■•••-
,:NITS AND
EL DOT ROCHLOFIINA'PON
--I
CELLS
)•-•-•
iXF
2-
,
, ,
13
0.1
73
HYPOCHLORITE DOSING PUMPS
HYDROGEN REMOVAL TANK
Fic. 10.18 CW electrochlorination plant — system diagram
ELEcTROcHLoRINATION CELLS HYDROGEN mOVAL TANK
a.akv SWITCHBOARD
HYDROGEN GAS DETECTOR TEST VALVES
BATTERY ROOM
UNIT SWITCHROOM •
ii0V DC :0 .
1 220V
J
LI
7
fl
DC
4€Z D
5 •-1 48V
4
•
;
DC
0 L ri220v I
I i
U
DC
.2
0 1110V DC
!
L
I
..■-■■■■•■■
DOSING PUMPS
RECTIFIER UNITS
3 , 3kV SWITCHBOARD
CONTROL PANEL
BATTERY ROOM
FIRE PROTECTION EQUIPMENT
1 UNIT SWITCHROOM
Fla. 10.19 CW electrochlorination plant room — typical layout
ommon in the UK. Treatment of cooling water, boiler make-up feedwater and condensate are necessary to Pre ,rent plant corrosion, sludge build-up, scale for-
mation, organic growth and marine growth, any of which will detract from the operating efficiency and life of the plant. 835
Pi" Mechanical plant electrical services
Raw water from most sources contains salts of calcium, magnesium, sodium and potassium, together with chloride and sulphate ions, dissolved oxygen and carbon dioxide, and suspended solids. The concentration of these impurities varies with the source of the water and this, together with the use of the water, dictates the overall design requirements of the feedwater treatment plant. Feedwater treatment comprises three stages; the main water treatment plant, the boiler feedwater chemicaldosing and the condensate polishing plant. The function of each plant is briefly described below and their disposition in relation to the feedwater system shown on Fig 10.20. The function of the main water treatment plant is to purify the raw water intake and render it suitable for use as boiler make-up water. In the pre-treatment section, the raw water is dosed chemically for pH correction and solids coagulation, and then filtered to remove suspended solids. After filtering, the water is allowed to settle in a tank before being transferred to the ion-exchange section.
Chapter io
The ion-exchange section removes contaminants and organic material which has not been filtered out duri ng the pre-treatment process. Filtered water is passed through resin-exchange cation, anion and mixed-bed units after which it is of adequate quality for suppl y to the boiler make-up water tank. During the ion-exchange process, the resins are de_ pleted. Regeneration equipment is provided which receives, prepares and dilutes regenerating chemicals, namely sulphuric acid and caustic soda. These a re passed through the resins to restore their ionic exchange capacity. The function of the boiler feed water chemical-dosin g plant is to remove any traces of oxygen left after de. aeration, to reduce the pH (acidity) level and to inhibit corrosion. Ammonia and hydrazine liquid concentrates are mixed with deionised water and the solutions injected into the boiler feedwater, the ammonia to reduce the pH value and the hydrazine to remove the traces of oxygen. The purpose of the condensate polishing plant is to polish, i.e., maintain low levels of suspended solids,
TANKS
MAIN WATER TREATMENT PLANT FIG 1021. 1 0.22,10.23
L
CONCLC 7:4 ■ MONITORING
FIG. 10.20 Feedwater system now diagram showing the interrelationship with water treatment plant
836
Water treatment plant
deionise the turbine condensate recovered from ''be condenser wells. Condensate is demineralised by ed-bed units and returned to the steam generator ini faclwater system. The levels of suspended solids and value are controlled to minimise corrosion of ,he pH :he boiler drums, tubing and auxiliary equipment. Fi,,ures 10.21 and 10.22 show a simplified arrangehe pre-ireatment and ion-exchange plants at xrit o f t ol nuclear power station located on the coast pt 3 .,nd utilising sea water. Primary water feed is by two ooro duty raw water pumps through sand-filter units t a filtered water tank, from where it is pumped by ,0 11 duty filtered raw-water pumps through rree 50 70 drion units and anion units. Two 100% duty booster pumps feed the water through mixed-bed units to the roerve feedwater tanks. Figure 10.23 shows a simplified regeneration system. Three regeneration water pumps supply water from the feedwater tanks to acid and caustic dilution recerve
tanks and thence to the respective anion, cation and mixed-bed units of the ion-exchange and condensate polishing plants. Figure 10.24 shows the condensate polishing plant. The primary condensate feed is via the condenser extraction pumps into the mixed-bed units and thence to the de-aerator via the feedheating units as shown in Fig 10.25. Figure 10.26 illustrates the feedwater chemical dosing system. Two 100% duty ammonia dosing pumps and two 100% duty hydrazine dosing pumps are provided to treat polished condensate and de-aerator inlet/outlet feeds. Cooling water is treated to prevent scale deposition, organic growth and algae on heat exchange surfaces and to prevent marine growth. Cooling water treatment consists of intermittent dosing with chlorine or of continuous dosing with sodium hypochlorite. Sodium hypochlorite dosing is pre-
STATIC MIXER • • •
SAND FILTER
AIR BLEED
DISCHARGE VALVES
AIR BLEED
X
DISCHARGE VALVES
RAW WATER RUMPS
FILTERED
SUCTION VALVES
WATER PUMPS
•
I RAW WATER I NLET
SAND FILTER
"4■-•■■■••
'1/4....
• "
"
LOW PRESSURE AIR FROM AIR BLOWERS
FILTER BACKWASH
RINSE RE-CYCLE .1■111■1.1,
••■1.1•1••■
MAIN SYSTEM FLOW LOW PRESSURE AIR
• Ho. 10.21 Water treatment plant — pre-treatment system 837
Mechanical plant electrical services
Chapter 1()
OUTLET TO REGENERATION SYSTEM
LOW PRESSURE AIR FROM AIR BLOWERS
I NLET FROM PRETREATMENT PLANT
›cl.
RESIN TRAP
RESIN TRAP RESIN TRAP
3
fX1-
BOOSTER PUMPS
ACID TO MIXED BED ONUS FROM ACID DILUrioN TANK
ACID TO RFR CATION UNETS FROM CATION DILUTION TANK
CAUSTIC 4- 4 TO MIXE BED UNITA
FROM
FILTERED WATER TO BRINE EJECTOR
CAUSTIC OILUTIONS TANK. MAIN SYSTEM FLOW
•
LOW PRESSURE AIR
— — ACID -. FIG.
CAUSTIC
10.22 Water treatment plant — ion-exchange system
ferred for coastal stations because it has been shown to be more effective in the treatment of marine growth. It also eliminates the dangers associated with the storage of liquid chlorine. The electrochlorination plant (sodium hypochlorite production and storage) at a nuclear power station is described in Section 6 of this chapter. Four dosing 838
pumps are provided to inject sodium hypochlorite into the cooling water system.
7.2 Electrical distribution system 3.3 kV and 415 V switchboards are provided to ensure maximum security of electrical supplies to the water
Water treatment plant
BRINE TO R.FR ANION UNITS (I ON EXCHANGE)
. MAIN SYSTEM FLOW ACID
FROM BRINE SATURATOR
CAUSTIC
AKE-LIP
PUMP
RESIN TRANSFER WA TER.'POL ISHING PLANT REGENERA T ION WATER PUMP
COm MON STANDBY PUMP
RESERVE FEEOWA TER I NLET BRINE MEASURE
TO DOSING PLANT
OUTLET MAIN TO CONDENSATE POLISHING PLANT •
FROM CAUSTIC MEASURE SYSTEM
EJECTOR
EJECTOR
EJECTOR
CATION DILUTION TANK
MIXED BED ACID DILUTION TANK
ANION CAUSTIC DILUTION TANK
CAUSTIC TO RFR ANION UNITS
ACID TO RER CATION UNITS
1
EJECTOR -
MIXED BED CAUSTIC DILUTION TANK
CAUSTIC TO MIXED BED UNITS
FIG. 10.23 Water treatment plant — regeneration system
treatment plant. The distribution system is designed to minimise disruption to the plant operation in the event ot, . supply failure by feeding the plant from alternative w itchboards and providing interconnection facilities. For the water treatment plant described in the previous ection, the switchboards are divided into two sections, ach section being fed from independent sources and he two sections interconnected. The largest individual loads are the electrochlorinaOrs — typically 750 kW and supplied at 3.3 kV. The !
3.3 kV and 415 V distribution system for the electrochlorination plant is described in Section 6.3.7 of this chapter. Other water treatment plant loads are fed from 415 V switchboards via latched contactors, this type of contactor being used in view of the essential nature of the plant and the need to safeguard against spurious tripping. The main 415 V three-phase loads are as follows — two 30 kW raw water pumps, three 40 kW filtered water pumps, two 30 kW booster pumps, two 839
IF' Mechanical plant electrical services
Chapter 10
CONDENSATE INLET FROM REGENERATION PLANT
V A
MAIN SYSTEM FLOW
VALVE
I NLET MAIN •
•
•
RECIRCULATION LOOP
BYPASS VALVE
MiXED BED UNIT A
RESIN TRAP
RESIN TRAP
RESIN TRAP
■111■
CONDUCTIVITy ALARM
X CONDUCTIVITY ALARM
CONDUCTIVITY ALARM
FEEDWATER
OUTLET MAIN
RECIRCULATION PUMP
RECIRCULATION LOOP
Flo. 10.24 Condensate polishing plant — system diagram
3 kW recovered water pumps, three 50 kW effluent pumps and two 0.5 kW alum dosing pumps on the pretreatment and make-up plant; two 90 kW recirculation pumps on the condensate polishing plant; four 0.5 kW hydrazine dosing pumps, four I kW ammonia dosing pumps and, two 1 kW tank stirrers. 7.3 Electrical control A suite of control panels located in the water treatment plant building houses all the equipment necessary for the fully automatic control, monitoring and alarm annunciation functions of the plant, and manual control facilities for maintenance and commissioning. Selected alarms are repeated in the Central Control Room. 840
Plant operation is controlled automatically by programmable logic controllers (PLC). Logic-initiated solenoid valves, which actuate the pneumatically-operated and motorised control valves, are fitted with override facilities which allow the plant to be controlled manually in the event of automatic control system failure. 7.4 Motor drives The majority of electric drive motors are 415 V threephase, squirrel cage, totally-enclosed fan cooled types arranged for direct-on-line starting and having a degree of protection of 1P54 or CP55 weatherproof to suit the environment.
EJ OILLR
.t,LN L RA I 0t-t 1■•■•■
LP
•••■••
LP
J 1
1
Mil••••••■••
F. X 1 RAC rioN PUMP
DEAERATOR CONDENSERS (THREE OFF) .1.111.■
immimil•• ■■■■
AN1) : STEAM':
CONDENSER!
BOILER FEED PUMP TURBINE
BOILER FEED PUMP
HEATERS -
- MAIN STEAM SUPPLY
1 --
r----
DRAIN COOLER
. .......-.1\
i
-- REHEAT/BLED STEAM FEEDWATER/CONDENSATE • - - DRAINS
Ii.. 10.25 Condensate and feedhealing system
TURBINE MOISTURE
OCI RAC r C.)N CONDENSER { -,..
luelci 1uauJleaJ1 Jalem
LP
Mechanical plant electrical services
Chapter 10
I> AMMONIA MEASURE
0:1 R{G
2,1D E A TIcN TE R SUPPI_
VENT
DESCRIPTION
SYMBOL
MANUAL VALVE
T
>O
I I PT4
=z1
MANUAL VALVE (NOR MALL Y SHUT)
1
LEVEL INDICATOR FLOW INDICATOR VARIABLE STROKE PUMP
AMMONIA DOSING DELIVERY
PULSE DAMPER
on
LIME STRAINER
1:41
RELIEF VALVE
Fia, 10.26 Feedwater chemical dosing system
7.5 Frost protection Trace heating and immersion heaters are provided, as necessary, to protect the plant against frost. A detailed description is given in Section 5.1.7 of this chapter. 7.6 Electrically operated valve actuators -
Motorised valves have actuators equipped with integral control gear. To facilitate maintenance and replacement, each actuator is equipped with flexible control and power cables fitted with connectors which couple with a disconnection box. Fixed cabling is glanded and terminated in the disconnection box in the normal manner. 842
8 Coal, ash and dust plant 8.1 Coal handling plant 8.1.1 General description of plant
Coal is delivered to a power station either by sea, canal, road or rail: rail is the most common in view of the large and regular deliveries of coal required by large modern power stations, especially since most large coal-fired power stations are located inland. On those stations supplied by water, three methods are used to unload coal from ships or barges: • Various designs of continuous-unloaders which remove the coal from the barges or ships and feed it directly onto a twin conveyor system.
Coal, ash and dust plant
HYDRAZINE '.1 EAS Li RE
--JUNIT HYDRAZINE DILUTION TANK
UNIT HYDRAZINE DILUTION TANK
1Amm0NrA/ ,
)1YDRAzINE
CATION rANK
›Ti
174
AMMONIA/HYDRAZINE DOSING DELIVERY
HYDRAZINE DOSING DELIVERY
Flo. 10.26 (cont'd)
Feedwater chemical dosing system
• Harge-unloaders which hoist and tip the barges one a ti me to discharge their loads of up to 200 t \! coal into hoppers, from where it is fed by paddle :20,.lers onto a twin conveyor system. • rra%elling/grabbing cranes which load the coal into .
'oPPers, from where it is fed by paddle feeder onto ,i[o.in conveyor system.
•
commonly, coal is delivered by trains working power station on a merry-go-round system in the trains remain coupled and move contin`IY . at a speed in the order of 0.8 km/h during the oading sequence. The wagons, which are of the :Ter-bottom type, pass through the unloading area ,re they discharge their loads into underground hop-
.
1
pers and are automatically weighed 'full' and 'empty' to establish the amount of coal delivered. A minimum of two conveyor systems, each of which can be operated independently, are fed by twin-paddle feeders from the associated wagon unloading hopper. A typical rail unloading plant is illustrated in Fig 10.27. From the wagon unloading hoppers, the coal is transported by a system of electrically-powered conveyors and flap (diverter) valves, either directly to the boiler bunkers or to the coal store. Metal detectors and magnetic separators divert tramp iron and metallic objects from the coal stream. Trash screens remove non-metallic objects and one or two stages of vibrating screens and crushers ensure that the coal is reduced to a size and consistency which is suitable for the mills to 843
1PP' Mechanical plant electrical services
Chapter 10
PRIMARY DOOR CLOSING MACHINES HOPPER EXIT EQUIPMENT CUBICLE
WAGON SHAKER AND How
LOCAL SIGNAL CONTROL PANELS
" — : NVEVI)R •;11
CENSOR C)R r Posrs
,,,
EN •
•,•
DC C R
_
" ACH INET
- LCONDARy DOOR, , CL05:NG MACHINE S HAND WINCH
1- L A iAL JE
S PA RE I PADDLE NT E N CFEE EBD AEYR
', LAP VALVE . .iAND OPERATING ' .7, EAR
MAINTENANCE
CONVEYOR
TAIL
DRUM
DOOR OPENING MACHINES N„ (6 EACH [RACK)
HOPPER GRIDS
TRANSFER CHUTES CONVEYORS TO JUNCTION HOUSE
FE°.
10.27 Coal handling plant — rail unloading plant layout
handle. Belt weighers are provided to determine the weight of coal being delivered to store, reclaimed from store, and delivered to the bunkers'. Coal fed onto the bunker feeder system is automatically sampled. The conveyor system incorporates junction houses in which plant is located. A typical junction house is shown in Fig 10.28. At most stations coal is delivered to or reclaimed from store by travelling stacker/reclaimer bucket-wheel machines. These machines are boom conveyor systems which stack or reclaim coal whilst travelling the length of the store on rails. Dust suppression or extraction systems are provided at strategic locations, such as wagon unloading hoppers, bunker tops, crusher buildings and junction houses, where the concentration of airborne coal dust might otherwise constitute a hazard. Figure 10.29 shows the coal plant conveyor system at a large power station. 8.1.2 Electrical supplies
\lost loads for flap valves, conveyors, vibrating feeders, crushers, paddle feeders, magnetic separators, fans and trash screens generally are supplied at 415 V three-phase 50 Hz from the 415 V Coal Plant Switchboard, although 3.3 kV supplies may be used when the duty demands. Stacker/reclaimer machines are supplied at 3.3 kV. Electrical distribution is designed to safeguard the 844
independent operational requirements of the duplicated coal plant facilities and to ensure that an electrical fault will not result in the total loss of coal supplies to the boilers. A typical distribution diagram is shown in Fig 10,30. 8.1.3 Electrical control
A control desk and mimic panel in the Coal Plant Control Room forms the central control facility for the coal plant. Manual/automatic control facilities and plant status indicators are provided. Control of the stacker/reclaimer machines is from the machines, only status indications being provided in the control room. Wagon unloading and lineside signalling control is from either the control room or the wagon unloading house, supervision of this and other important aspects, such as the coal stores, being assisted by television monitors and cameras (Fig 10.29). Sequential control of conveyors and paddle feeders is provided for start-up and shutdown. This is essential to avoid coal spillage which might otherwise occurdue to the differing rates of acceleration and decelera tion of the conveyors attributable to the wide variation in their lengths and lifts. 8.1.4 Conveyors
Conveyors are driven by 3.3 kV or 415 V three-phase 50 Hz squirrel-cage induction motors through ALIA
Coal, ash and dust plant
JUNCT I O N HOUSE
PRIMARY DRIVE CONVEYORS WA
ACCESS FLOOR SECONDARY DRIVE
TRANSFER CHUTES I
CONVEYORS
TENSION WEIGHT
GRAVITY TENSION PULLEY
no. 10.28 Coal handling plant
couplings to protect the conveyors during start-up. The motors are totally-enclosed, fan cooled, with a degree of protection of I1 3 55. Each conveyor is equipped "ub an emergency trip-wire system running the full
—
junction house layout
length of the conveyor alongside the access way. Switches are located at intervals along the trip wire. The trip wire may be a wire rope arranged to operate trip switches directly, or a cable designed to trip relays 845
Mechanical plant electrical services
Chapter 10
rOWER 3
TRANSFER Tav.ER 2
SHUTTLE cONVE fOR
BUCKET WHEEL MACHINE NORTH STORE NORTH 26
;UNCTION HOUSE
2
UNLOAERNG HOPPERS
JUNCTION HOUSE 1 JUNCTION HOUSE 2
:UNCTION HOUSES
'O A BELT WE
'AERGENCY sTocKCuT , ONJ d' EVO'FIS
SEPARATOR EMERGENCY RECLAIM HOPPER
3 -T N V G HE RS
TRASH SCREENS RECLAIM FEEDER 2
RECLAIM FEEDER , JUNCTION HOUSE 5
28 BUCKET WHEEL MACHINE SOUTH 29 31
30
CAMERA
STORE SOUTH
Fin. 10.29 Coal handling plant — conveyor system
846
Coal, ash and dust plant
11/3 3kV
11/3 3kV COAL PLANT • AUXILIARY TRANSFORMER B
PLANT PAUX IL 1ARCOALTRANSFORMER 'A' Y
SWITCH BOARD A'
SWITCH BOARD 'A. 4 3 3kV COAL PLANT AUXILIARIES BOARD
STACKER/ RECLAIMER . MACHINE 1 CONVEYORS A
CONVEYORS 13 .
STACKER/ RECLAIMER MACHINE 2
3.3/0. 4 15kV COAL PLANT AUXILIARY TRANSFORMER B
3.3/0.415V COAL PLANT AUXILIARY TRANSFORMER 'A
SWITCH BOARD /. 4:
•
SWITCH BOARD 'B'
(/5 CONVE YORS AND MISCELLANEOUS PLANT A SIDE
FIG.
10.30 Coal handling plant — power distribution diagram
upon deflection. The trip switches are connected directly into the conveyor drive motor contactor control circuit to cause the conveyor to stop when initiated. Each conveyor is fitted with a speed detector. Beltdriven speed detectors are prone to slip when dusty or Wet and have been dropped in favour of electronic Pulse or similar types. The conveyor is tripped if the conveyor belt slips or breaks. 8 1
CONVEYORS AND MISCELLANEOUS PLANT 13 . SIDE
. .5 Stacker/reciaimer machine The stacker/reclaimer machine is supplied by a reeling-
drum trailing-cable system. These cables carry the power, control and communication supplies necessary for its operation. The machine may be operated by electric motors or electrohydraulic devices. The 3.3 kV three-phase 50 Hz power supply is stepped down to 415 V by a transformer located on the machine. Supplies for bucket wheel, boom conveyor, travel and boom control drive motors are taken from a motor control panel specially designed with 1P54 protection to prevent coal dust ingress. Drive motors are 415 V three-phase 50 Hz totally-enclosed, 847
Mechanical plant electrical services fan cooled squirrel-cage induction motors with protection to 1P55. An operator's cabin is located to give a clear view for operational purposes. All control equipment is of dust-tight construction having 1P54 protection. A complete set of controls for both manual and semiautomatic operation is provided. Driver supervision is required at all tii cti2s 1.0 ullen. ise stacking and reclaim, inv. operations and to ,af:itttuard the machine. Controls are provided for travel, !tiff and slew motions, and for other service requirements, such as audible alarms, machine access lighting and floodlighting. Deadman-type controls are provided for travel, luff and slew motions, these controls automatically returning to the off position when released by the operator. To safeguard personnel, boom and elevator conveyors are equipped with trip-wire systems. Emergencystop pushbuttons are located on access platforms, in the operator's cabin and in the electrical equipment enclosure. An emergency trip causes all machine drives to be de-energised.
8.2 Ash and dust handling plant 8.2.1 General description of dust handling plant Dust is collected in hoppers below the precipitators and boiler economisers (Fig 10.31). Air-jet blowers transfer the dust from the precipitator dust collection hoppers to the precipitator surge hopper, and from the economiser dust collection hoppers to the boiler-grit surge hopper. A boiler-grit pump transfers grit from the boiler-grit surge hopper to the precipitator surge hopper. From there, dust is pumped into a common storage bunker. Aeration fans ensure that dust in the surge hoppers and in the storage bunker is maintained in a fluid state. From the storage bunker, dust is transferred by rotary feeders onto a system of conveyors, which feed it to the disposal area. The dust-handling plant for a large modern power station is outlined in Fig 10.32.
Chapter 10 The motive water is pumped from the ash pits t o settling lagoons. After settlement, it is recirculated by return water pumps, via the ash water reservoir, t o the HP sluice pumps. The system for a large modern power station i s illustrated in Fig 10.33. 8.2.3
Electrical supplies
The supply requirements of the ash and dust handling plant are met by an integrated distribution system, comprising 3.3 kV and 415 V three-phase 50 Hz switchboards, diversely supplied and interconnected to ensure maximum system availability and to minimis e disruption due to supply faults. The 3.3 kV switch. board feeds the HP sluice pumps and the transformer feeders to the 415 V switchboard. Other requirements, such as movable ash hoppers, trace heating, ash-grabbing crane, conveyor drives, ash crushers, dust conditioners, rotary feeders and aeration fans are suppli e d from the 415 V board. 8.2.4 Electrical control With the exception of the ash-grabbing crane and mobile dust hoppers, the ash and dust plant is controlled from a mimic control panel, normally sharing a control room with the coal plant. Local control facilities are provided on the major items of plant to satisfy safety and maintenance requirements. A sequence control and interlock system is provided to ensure correct start-up and shutdown. This system covers airheater, economiser and precipitator hopper jet-blowers, grit and dust pumps, dust bunker aeration fans, rotary feeders, dust conditioners, conveyors, and other items of plant which must be operated in a specific sequence to ensure the correct functioning of the overall plant. Direct control is provided of sluice pumps, glandsealing water and make-up pumps. Instrumentation, discrepancy equipment and alarm equipment is incorporated in the mimic control panel to enable plant status to be monitored.
8.2.2 General description of ash handling plant The design of the ash handling plant is dependent upon the method of ash disposal. It may be pumped into a disused quarry or transported from the power station for processing into building materials. A typical system, outlined below, includes both facilities. Ash from the boiler is collected in a hopper directly below the furnace, whence it is removed by high pressure water jets and discharged, via sluiceways, into ash crushers. The crushed ash falls into ash tanks, and is then projected by water-jet pumps supplied by HP sluice pumps through discharge pipelines to ash pits, where it is allowed to settle. After settlement and drainage, the ash is removed by grabbing crane for disposal by road vehicles or by conveyor to a disposal pit. 848
8.2.5 Mobile ash hoppers Ash is discharged from the ash pits via mobile ash hoppers onto a conveyor system for disposal. Each hopper is supplied at 415 V three phase 50 Hz through a reeling-drum type trailing-cable system. Motor control gear, protected to 1P55 weatherproof, is provided on the hopper for travel, traverse and conveyor functions and for an anti-collision system. Drive motors are 415 V three-phase 50 Hz totally-enclosed fan cooled squirrel-cage induction motors. -
8.2.6 Ash-grabbing crane The ash-grabbing crane is generally as described in Section 3 of this chapter, and is supplied at 415 V
Coal, ash and dust plant
00-0-
0 -0 -0 -0 0 0
-
-
0
9
9
0
00
PREL:rPrTA TCR OUST CCLL E ,ON HOPPERS
PREC1P1 TA FOR SURGE HOPPER
Fn
STANDBY
ST ANO8Y
le r ts,
0
Lbdi
rrA
RE CIF, TOR DUST PUMPS
-c —0
ed BOILER GR SURGE HOPPER
ECONOMISER DUST COLLECTION HOPPERS
BOILER GRITT PUMP GRI
nd
In?! a ies fy
BOILER UNIT I
oo
ed !rri on nd a
TARGET 80x
REEK AIR FANS
REVERSE AIR FANS
666
1.Mmir
DUST
oo
BUNKER
AERATION FANS
AIR SLIDE FANS
■•■•11 ROTARY FEEDERS
AIR SLIDE CONVEYORS
0 0 0
iel CONvE TORS
w A TER MAIN 414. ■
T-.
PROBE AIR FANS
I
FIXED CONDITIONERS
I
I
DUST CONDITIONERS
FLAP VALVES
DRY OUST COLLECTION BY ROAD VEHICLES
DUST CHUTE JUNCTION
CONVEYORS HOUSE 4
DUST CONDITIONER
in V
House
FIG. 10.31 Dust collection plant 849
Mechanical plant electrical services
Chapter i o
Fic. 10.32 Dust handling plant
three-phase 50 Hz by a reeling-drum, trailing-cable systern. 8.2.7 Trace heating
The precipitator surge-hopper is equipped with trace heating to prevent condensation within the hopper during shutdown. If not prevented, heavy condensation would solidify the ash and cause blockages. 8.2.8 Local control panels
Local control panels and cable termination boxes are provided of weatherproof, dust-tight construction to IP55 or IP65, depending upon the severity of the environment. Facilities are provided on local control panels for full manual control of the plant item. 8.2.9 Conveyors
Conveyors are driven by 415 V three-phase 50 Hz squirrel-cage induction motors through fluid couplings 850
to protect conveyors during start-up. The motors are totally-enclosed, fan cooled with protection to 1P55. Each conveyor is equipped with an emergency tripwire system running the full length of the conveyor alongside the access way. Switches are located at intervals along the trip wire. The trip wire may be a wire rope, arranged to operate trip switches directly, or a low voltage electric cable arranged to operate a trip relay. In the latter system, a trip relay is energised through the cables and the switches between which they are suspended. Upon deflection of a cable, the relay circuit is broken by the associated switches. Since a cable fault or breakage will also cause the trip relay to operate, the system is self-monitoring. The contacts of the trip switches or relays are connected directly into conveyor drive-motor contactor circuits and cause the conveyors to stop when the trip is operated. Each conveyor is fitted with a speed detector. Belt driven speed detectors are prone to slip when dusLY or wet and have been dropped in favour of electronic
Electrostatic precipitators ,,,u1se or similar types. The conveyor is tripped if the belt slips or breaks. . 01 ,,eyor sump
8. 2.10
p u mp, grit pump and dust pump
co ntrols
mps are controlled by sump content measurel oci being measured by ultrasonic :L,,:ho-detection systems which utilise the reflective :,.rjeteristics of the surface of the water. Probei measurement systems are not used since the le , e IJ-up of deposits on the probes due to the pre. ash and dust in the sumps can prove troublepu
.
the su mp
of
plates, which channel the gases and attract the charged dust particles. The accumulated dust is released from the electrodes by intermittent mechanical rapping and is collected in the dust hoppers below. The discharge electrodes are situated between the collecting electrodes/plates, suspended from insulators. Dust tends to accumulate on these electrodes in small quantities and this is also released by rapping, to maintain efficiency. Collecting electrodes along the length of the precipitator are divided into a number of zones, typically six, each of which is provided with its own high voltage and rapping gear. For a typical power station having 500 or 660 MW units, the total gas flow from a boiler
OUST EilAKER HOUSE .. u NCTON HOUSE
AIR SLIDE CONVEYORS
JIAICTICN HOUSE BELT WELCHERS JUNCTION HOUSE
DUST CONDITIONER HOUSE
FIG.
10.32 (coned)
Dust pumps and grit pumps are controlled by hopper , ,, ruent measurement, load cells or level probe systems -;:ng used for this purpose.
9 Elecrrostatic precipitators
9.1
General description of plant
ln electrostatic precipitator removes dust from flue -'r-kes by charging the particles in an electrostatic field up between discharge and collecting electrodes ..ithing them to be separated from the gas stream. The 'I , es are drawn through large chambers containing ' l lecting electrodes in the form of large vertical flat
Dust handling plant
is shared between three precipitators, known as 'flows', each flow consisting of approximately sixty gas paths. Figure 10.34 shows the general arrangement of a precipitator having six zones. A DC voltage of between 20 kV and 30 kV, produced by transformer/rectifier units, is applied between the discharge electrodes and collector plates, the voltage being controlled automatically at a level just less than that which would cause flashover, to provide maximum discharge current (termed corona discharge), and hence maximum operating efficiency. In order to maintain a free flow of dust, the dust collecting hoppers are electrically-heated and thermally-
insulated to maintain a high dust temperature. Compacting of the ash is prevented by electrically-driven aeration fans feeding air into the dust hoppers. 851
Ilr Mechanical plant electrical services
Chapter 10
:Rom EmERGENCY DUST SLI.,CE.WAy
FAw 5MEV AA A KE-_,
ASP •VA'IEF FESER,O.r.
ASP SRI- I- •IG L >GOONS
X
0
I I
I CL)
0 HP SA ,C.EWATER FuAiPS
(
I)
(
2)
(
-F SLAPCE P• yP ^LA vc •NATER FuLIPS i ) SEAL •
LJ
X X
F50.51 GENERAL SE.V•CE WATFR SYSTEM
HOPPER
7
7
SUPPLY
SYAL 7, OUGH WATER SUPPLY
SEAL WA .z a 1110 JGP
XX
,
SEAL
rROu c k OV E R F LOW
":"-
\I/
I
\ / X
/
/ I \ jr:' rI I" " I \ 1. 1 ... /I I \ ''' IN SOILER ASH POPPER \1.1 \I/ \I/ 1I., \ I/ \ I./ \1/ LLI.FmTIENAG 1111111.11.1111
II " I
\ I/
In
• •
11111.7!
•
In
XX XX XX XX XX XX
X Xi
OVERFLOW
S•_,CE WATER
TO EMERGENCY OUST JET PUMPS
--•
AGITADON NOZZLES
SLUICE WATER GENERAL SERVICE WATER
R•■•••=1 ASANSLLARY
FIG. 10.33 Ash handling plant 852
I\
-,
\I/
..
: •
•
•
T
XX XX XX XX XX XX
ASP 0151185
STRANER
/
Electrostatic precipitators
O•S.7 , -, POE E,ECrROOES G.KRP,o GEAR
R,R•Poar
K OC
ENE) 70,4ECT
K Acor ACCESS DOOR
e+.
,
OEE * OE
,
C 7 ES MEC.•KI , CRL
WERLOCKEL, rE9.5
FIG. 10.34 Precipitator general arrangement
9.2 Electrical supplies 9.2,1
415 V switchboards
The electrical requirements of the precipitators are
supplied from 415 V three-phase 50 Hz switchboards, separate boards being provided for each precipitator flow. They feed high voltage control cubicles located with the switchgear in the Precipitator Control House. Other feeds go to the collector-plate rapper motors, 853
Mechanical plant electrical services
Chapter 10
discharge-electrode rapper motors, dust-hopper heaters and aeration fans, control house ventilation fans and hopper level equipment. Figure 10.35 shows a typical control house distribution equipment system. 9.2.2 High voltage control cubicles Each high voltage control cubicle accommodates the automatic control equipment, power thyristors and power distribution equipment associated with one zone of the precipitator gas flow. Controls and indicators for the precipitators are provided in the Precipitator Control House and the Central Control Room, control normally being carried out from the latter. Automatic and manual control facilities are available. Particular attention is paid to the design of the power thyristor and diode equipment to ensure high reliability and long service life, having regard for the inability of semi-conducting devices to withstand deviations outside their specified operating conditions. Overload and short-circuit protection are provided by high speed semiconductor fuses. Surge suppression circuits are incorporated to protect thyristors and diodes against supply voltage transients which may occur in service. Thyristors and diodes are conservatively rated in respect of their current carrying ability, junction operat-
A rN SUPPLY 4150/ 3 PHASE 50H t
1200A MAIN OFF LOAD ISOLATOR I NSULATOR HEATING DISTRIBU LION F USE BOARD
SOA FUSED SWITCHES
48kW
30A FUSED SWI TCHEs
151. 5kVA
4 I 5V 3 PHASE AND NEUTRAL
ico0A FUSED SWITCHES
615kV A
304 FUSED SWI ID1IFS
14•■
I 5A FUSED SRI t CHES
lEikW
3 6kVA
1SA FUSED SWI TCHEs
3 6kVA
64 FUSED SWI TCHES
5,
THERMOSTAT II of 241
DISCHARGE RAPPER MO TORS {6) COLO C T INC RAPPER MO TORS 1121
RAPPING CONTROL PANEL HIGH VOLTAGE CONTROL CUBICLE
TRANSFORMER/ RECTIFIER UNIT
NIGH VOLTAGE CONTROL CUBICLE
TRANSFORMER/ RECTIFIER UNI
HIGH VOLTAGE CONTROL CUBICLE
TRANSFORMER/ RECTIFIER UNI r
/ONE
I
DISCHARGE ELF 01110015
EAR THING SWITCH ZONE 2
DISCHARGE ELECTRODE S
IONS 3
DISCHARGE CT RODE S
EARTHING SWITCH
HIGH VOLTAGE CONTROL CUBICLE
Fs..
HIGH VOLTAGE CONTROL CUBICLE
TRANSFORMER/ RECTIFIER UNIT TRANSFORMER/ RECTIFIER UNIT
HIGH VOLTAGE CONTROL CUBICLE
11.4...
HOPPER HEATING CON rRot.
H
TRANSFORMER/ RECTIFIER UNIT 240/110V TR TRANSFORMER ( I OF 3)
7-
ip
ZONE
10.N0.1.EAR THING SWITCH ,
ZONE 5
io Nso.IEARTHING SWITCH ,
....■..m.ip
"...t),Z.AFt THING SWITCH I•
THERMOSTAT (1 OF 3)
ZONE 6
•
DISCHARGE ELEC [NODES
DISCHARGE ELECTRODES DISCHARGE ELE CTRODES
HOPPER HE A TER
VENT FAN 1
VENT FAN 2
HOPPER LEVEL DISTRIBUTION FUSECIOARD
PROBE CONTROLLER (1 OF 9)
Flo. 10.35 Precipitator control house electrical distribution diagram 854
INSULATOR HEATER
1■1111Mw■
EAR 1HING SWITCH
VP'
240V SINGLE PHASE
ing temperature and heat-sink performance at th e maximum air temperature likely to occur inside th e equipment cubicle during operation. Automatic voltage control is provided by thyris_ tors. The electrode voltage is continually monitored and varied by the thyristor control circuits, usin g wave-chopping techniques to maintain the highest per. missible precipitator operating voltage and operati ng efficiency. Typically, the high voltage must be abou t 20 kV for corona discharge to occur. Random arcing may occur at about 32 kV so the automatic voltage control must maintain the voltage just below thi s level. Two basic systems of monitoring and controlling the electrode voltage are in use. In the first system electrode voltage, electrode current and AC supply voltage are monitored and compared. When arcing occurs the electrode voltage falls whilst the electrode current and AC supply voltage increase. This situation is recognised by the comparator and, by control of thyristors in the AC supply, the electrode voltage is reduced to the optimum level at which arcing ceases. In the second system, the arcing rate is monitored and the electrode voltage varied by control of thyristors in the AC supply to maintain the random arcing rate within acceptable limits commensurate with maximum operating efficiency of the precipitator.
HOPPER Hi ,. ;H LEVEL PROBE HOPPER LOW LEVEL PROBE
Fuel oil plant 9.2.3 T ra
nsformer/rectifier equipment
/rectifier equipment is supplied from The transformer phases of a 415 V three-phase 50 Hz supply. To ow lify high voltage connections, the equipment is ,inir on the top of the precipitator. In norma lly located . location, oil-tilled ONAN (oil insulation, natural his rctilation, air cooled, natural ventilation) equipment t used, the LNAN (synthetic liquid insulation, no Natural circulation, air cooled, natural ventilation) type employed to minimise maintenance: in partiheliw ular, this avoids the regular insulating-oil treatment necessary with mineral-oil insulated (ONAN) transrmers and the dangers associated with oil spillage. fo 0\;AN equipment is only allowed if located at ground l o el. Transformers comply with BEBST2 [20] and 35171 1191. Coolant-liquid-immersed rectifiers are solid sate to 8S4417 1261 9.2.4 High voltage chamber enclosures
Separate housings are provided for each precipitator zone as shown on Fig 10.34. Located on the top of the precipitator, they provide protection for the exposed HV connections and allow access for maintenance. \ccess is controlled by the maintenance interlocking ,\ s tem described in Section 9.3 of this chapter. 9.2.5 High voltage insulators
High voltage insulators are mounted out of the gas %tream and inside the HV enclosure for ease of maintenance. Each insulator is fitted with a thermostaneally-controlled heater to prevent condensation.
9.3 Maintenance interlocking and locking Maintenance interlocking is provided for each flow to ensure the correct sequence of operation of the LV transformer/rectifier supply cubicle isolating devices, 11V chamber earthing switch and HV enclosure access doors associated with each zone, so that safety of personnel is assured. Coded-key interlocks and exchange boxes form the basis of the interlock scheme. The scheme ensures that all zones of a flow are electrically isolated and mehanically shut-off by closing inlet and outlet dampers before access to the flow can be gained. Figure 10.36 hows a typical maintenance interlocking scheme. The interlocking scheme shown in Fig 10.36 allows half-zones to be isolated and earthed individually if a fault occurs, and the remainder to be operated normany. However, all zones must be isolated and earthed before keys are released from the exchange box to al ford access into the flow. Similarly, all access points ;nust be closed and secured, and the keys thus released inserted into the exchange box before HV supplies can be reconnected. ln addition to the interlocks, access ways which allow cntrY to the flow or HV enclosure are provided with ,
an independent system of locking. Isolating and EIV earthing switches are provided with an additional means of . locking in the isolated or earthed positions. This ensures the correct control of access by personnel.
9.4
Earthing
In addition to the normal earthing requirements, precipitators are provided with the following special earthing facilities to ensure the safety of personnel. HV connections are provided with isolating and earthing s witches which are operable from outside the HV enclosure. They ensure that all sections of the HV system are earthed. Operation of these switches is subject to the maintenance interlocking scheme described in the previous Section 9.3. In addition to HV supply earthing, provision is made for the connection of portable earths to the HV grids prior to personnel gaining access to a flow. The arrangement of portable earthing leads prevents the closure of access points when the earths are connected. This safeguards against restoration of the HV supplies when earthing facilities are being used.
9.5 Interference suppression HV rectifiers, connections, switches and leads are screened to prevent radio and television interference. 10 Fuel oil plant 10.1 General description of plant Fuel oil is required: • For main boiler start-up and, in some instances, for oil overburn to meet load requirements at coalfired power stations. • For main boiler firing at oil-fired power stations. • For on-load firing of auxiliary boilers. For all these systems, fuel oil is unloaded or fed into storage tanks which form the supply point for the oil feed system to the burners. Electrically-driven pumps are used to feed oil into the storage tanks, to transfer oil between tanks and to supply oil from the storage tanks to the burners. Since the oil is of high viscosity, its temperature must be raised to render it suitable for pumping and combustion. Storage tanks and oil pipes are heated continuously by steam, electrical trace heating or immersion heaters. On steam heated systems, electricallydriven pumps are used to transfer the condensate. When oil is delivered by rail or road tanker, it is not possible to drain the tanks completely using the main unloading pumps. Residual oil is gravity fed into an oil drain tank from where it is transferred to the main storage tanks using electrically-driven pumps. 855
Mechanical plant electrical services
Chapter 10
ZONE
4A 11
2
3
4
5
4A23
4A33
4A43
4A53
4A63
INSULATOR ENCLOSURE DOOR ROOF ACCESS (TOP GRID)
0
0
4A 1 4
4A24
4A34
4A44
4A54
4A64
4A 1 5 ,
4A25 0
4A35 0
4A45 0
4A55
4A65
4A 16 0
4A26 0
4A36
4A46
0
4A56
0
1
4A11 . .C1.
4A27
4A37 0
4A47 0
1
4A18 0
!
0
0
.0
4A66
0 4A57 0
4A38 a
PORTABLE EARTHING ACCESS GRID)
(TOP
0
0
UPPER SIDE ACCESS (PLATE RAPPING GEAR)
4A67 0
LOWER SIDE ACCESS (PLATE RAPPING GEAR)
4A58 0
HOPPER SIDE ACCESS (BOTTOM GRID AND PORTABLE EARTHING)
FLOW 4A SECONDARY KEY EXCHANGE BOX
4A
FLOW 4A PRIMARY KEY EXCHANGE BOX
4A i 2 - 1 1 4Al2-
4A22-1
4A22-
H. V. , SUPPLIES TO HALF ZONES 1 4A1 '
4A32-
4A32-
H SUPPLIES t TO HALF ZONES 4A2
4A42-
4A42-
H.V. SUPPLIES !, TO HALF 11 ZONES 4A3
4A52-
4A52-
44,62-
4A62-
H .V. SUPPLIES TO HALF .t ZONES 4A5
SUPPLIES TO HALF ZONES 4A4
H .V. SUPPLIES TO HALF 1 ZONES 4A6
•
4
12
22f(
e
.
4A11
t
)
t
4A1
1T4Air,
°
+-'
7 11, )1
(74
1- -a
16-
'
4
)32
9 D.C.
•
" -1
'
HALF ZONE EARTH SWITCHES
H.V. D.C.
DOUBLE KEY INTERLOCKS (BOTH KEYS WITH SAME H.V. NUMBER) ON TRANSFORMER D .c, EARTHING SWITCHES
52
11..1
H.V. D.C.
D.C.
A
HV. D.C.
14A21
4A61 4A20
1
4A6
I
TRANSFORMER-RECTIFIER SET
4A60 CONTROL CUBICLES FOR TRANSFORMER-RECTIFIER SETS
4A2 4A20
4A30
4A40
4A50
4A60
NOTES 1 NUMBERING OF LOCKS AND KEYS IS SHOWN FOR PRECIPITATOR CASING 4A FOR OTHER CASINGS BOILER NUMBER AND LETTER WILL CHANGE ACCORDINGLY 2 POSITION OF KEYS DURING NORMAL SERVICE (PLANT ENERGISED) IS SHOWN BY THE SYMBOLS •
LOCK DESIGNATION ZONE NUMBER
0
KEY TRAPPED IN EARTHING SWITCH OR DOOR LOCK KEY TRAPPED IN EXCHANGE BOX
4 KEY 12-FITS LOCKS 12- AND 12 KEY 12 FITS LOCK 12 ONLY
PRECIPITATOR LETTER BOILER NUMBER TYPICAL KEY AND LOCK IDENTIFICATION
Etc. 10.36 Precipitator maintenance interlocking system
856
-4
11411pPP" — Fuel oil plant 10,37 shows the fuel oil system at a 2000 MW,
Fi o Figure - station designed to handle fuel oils delivered 10-6 owe r to ship an d vary ing in viscosity from 24 x 2 (24-1500 centistokes) at minimum -3 rn ,'s 10
temperature. Electrical trace heating is provided and operates continuously when c h supPIY pipework lightest (distillate) oils are being pumped. 111 h ut the is used in the fuel-oil heaters to raise the oil afl1 .cmperature to that required for combustion, 140 ° C ° , r heavy oil and 43 C for distillate oil. Unburnt hot il from the burners is recirculated back to the storage -e
supplies and allows for the routine maintenance of pumps. Pump drives are 415 V three-phase 50 Hz squirrelcage induction motors, totally-enclosed, fan cooled and arranged for direct-on-line starting, using contactors. A minimum degree of protection of IP54 is provided, except for outdoor use when IP55 weatherproof is normal.
10.3 Oil heating
o
choice of electrical or steam heating depends
The availability of steam and the economics of inn o the
10.3.1 Tank heating — electrical
ailing and operating the heating system. Electrical :race heating is ideal for oil pipelines since the heat to maintain the oil in a fluid condition is needed ely small. Because of the large quantity of oil in ,:orve tanks, steam or electric heating is viable and of steam at the storage tank location is :he acailabtY consideration. Fuel oil heaters require a large major and steam heating, when it is readily availat input ahle at that location, is preferred.
I mmersion heaters are supplied at 240 V from a 415 V three-phase and neutral supply, their position in the storage tanks being below the burner feed pump takeoff level to ensure that they remain immersed in oil at all times. The heaters are controlled by two thermostats connected in series with each other: one thermostat functions normally to control the heater supply contactor, the other is a safety device to trip the contactor when the oil temperature rises above the normal limit. To ensure that operation of the safety device is recognised, it has to be manually reset.
10.2 Pumps
10.3.2 Tank heating — steam
the design of the system and the number and rating 01 the pumps ensures maximum availability of oil
Steam flow to heating coils is regulated by thermostatically controlled steam valves, the arrangement of
/
KEY
ER
EXPORT
AUXILIARY JETTY
:p.sPoRv E v POW OIL
4
MAIN FUEL OIL RECIRCULATING
FLOWMETEFI STATION ••••
FUEL OIL HEATER BANK 3 YPOAT METER 5_A , ON
55
FUEL OIL HEATER BANK 2
1-
BOILER 3
L_B_CILER 2
—
HOSE CONNECTIONS
MIXING CHAMBER
VISCOMETER
DOKh MAIN FUEL OIL PUMPS
7
E.
2
Z>
04.3
— 1,41Doe,
FIRE VALVE
-444 RECIRCULATING PUMPS
STRAINERS
I
BO I
BOILER TRiP VALVE BOILER TRIP VALVE
EXPORT
PUMPS
SPILL CONTROL VALVES
L
L
-0-
E
3Z
,77 . 2
-
R1.04— CONTROL VALVE
FIG, 10.37 Fuel oil system 857
11, Mechanical plant electrical services the thermostats being as described in the previous Section 10.3.1. 10.3.3 Pipe heating
—
electrical
Pipe heating is achieved by trace heating applied directly to the surface of the pipe or embedded in the thermal insulation. Directly applied systems can be supplied at 240 V 50 Hz, since they are protected against accidental damage by the thermal insulation. For safety, embedded cables are supplied at 110 V 50 Hz by a transformer which has its 110 V winding centre-tapped to earth. Temperature control is by thermostats equipped with contacts which operate to raise an alarm when the control temperature band is exceeded.
10.4 Storage tank instrumentation Storage tanks are equipped with two high-level and two low-level proximity switches. The first high-level switch trips the filling pump, closes the inlet valve and initiates a remote alarm; the second initiates an extrahigh level alarm if the oil level rises substantially above the first switch. The first low-level switch initiates a remote alarm; the second initiates an extra-low level alarm and trips the oil heating supplies if the oil level falls substantially below that detected by the first switch. This maintains the oil level above the top of the outlet pipe. Local and remote oil level and temperature indications are provided.
10.5 Valve actuators AC motorised valves equipped with integral contactor gear are used in oil pipelines. Actuator motors are either totally-enclosed (TE) or totally-enclosed fan cooled (TEFC), squirrel-cage induction motors of weatherproof construction (IPW to BS4999) [2], suitable for operation on a nominal 415 V three-phase 50 Hz supply. Thermal protection is built into the motor winding in accordance with BS4999, part 72 [2]. The motors have high torque and low inertia, and are designed for continuous operation without injurious heating for one complete travel of the actuator or 5 minutes, whichever is the shorter, when the supply voltage is reduced to 75 07o nominal at 50Hz. This ensures high reliability in service throughout their design life of 30 years. The actuators have a degree of protection to [ P65 of BS5490 [3] and are capable of operation in steam and dust laden atmospheres within the ambient conditions defined in BS5967 Part 1 [27] — operating conditions for industrial process measurement and control equipment — Class D1 (5 to 100% relative humidity, — 25 ° + 70 ° C). Housed in each actuator enclosure are a 415 V threephase 50 Hz reversing-type contactor, toss of supplysingle phasing protection, a 415 V/110 V transformer providing 110 V AC control supplies, valve open/close/ 858
Chapter 10 stop controls, a remote/local control selection switch and open/close/stop relays for remote control. Po wer and control connections are carried in flexible cables from the actuator to a local termination box. Plu g and socket connections into the termination box facilitate the maintenance or replacement of the actuator without disturbing the fixed, armoured cable conne c . tions into the termination box. Each actuator is equipped with a valve position indicator, a potentiometer for remote position indica_ tion and valve open/close limit switches for remot e control and indication purposes.
10.6 Lightning protection A lightning protection scheme is provided for the oil storage tanks by conductors connecting the tank to earth electrodes.
11 Air compressors
11.1 General description of plant Compressed air at various pressures and flow rates is produced by compressors, normally electrically-driven, to satisfy the requirements of control and instrumentation, dust plant jet-blowers and dust pumps, boiler sootblowing, automatic boiler control, boiler blowdown, turbine forced cooling, breathing apparatus and reactor purging as appropriate to the type of power station. The main building complex of a power station is served by two primary compressed air systems — 'general services air' and 'control and instrument air'. Figures 10.38 and 10.39 show typical control and instrumentation and general service compressed air systems for a power station. The 'general services' system is designed for a flow rate of 0.4-1.0 m 3 /s at pressure of 7.2 bar, the 'control and instrument air' system for 0.2 m 3 /s at 8.5 bar. Certain plants remote from the main complex, such as those producing hydrogen and sodium hypochlorite, are provided with independent air compressor plant. Control and instrumentation air system requirements are most stringent in respect of the quality of the compressed air produced and its integrity. A typical system consists of two or three 100% duty electricallydriven air compressors, each complete with air coolers and oil/water separators, feeding two independent air receivers and air dryer systems via a manifold. A typical general services air system consists of two 50% duty electrically-driven air compressors, each complete with air coolers and oil/water separators, supplying a common air receiver.
11.2 Air compressor drive motors The drives are usually squirrel-cage induction motors. suitable for direct-on-line starting on 11 kV, 33 kV
Air compressors
DO15 4
[
5CLECTDR ES PRESS,PE
,
LOV. AFT — PCCOLER
■•1•10
• 4-04-Q
Pa
APE
•
■•
1;;.4■.
■•
•■■•=4.
,
N rERCO O LE R
PRE TER
Lf_L 1 1
om■wm
P
NA
,
7P
FIG. 10.38 Control and instrumentation compressed air system
. , r 415 V
three-phase 50 Hz supplies, of totally-enclosed construction, as described in Section 2.2 this chapter. They drive the compressors through V-belts,or flexible couplings and gearboxes. The -belts and flexible couplings protect the motor from Ju.),k loading and vibration.
proximately 3.5 kW, at 240 V single-phase 50 Hz. Heaters are equipped with dual thermostats, one for normal temperature control and the other acting as a safety device in the event of failure of the control system. The latter is manually reset and initiates remote and local alarms to warn of failure.
11
11.4 Automatic and safety controls The compressed air systems are designed to operate automatically, all operating conditions, such as air pressures and temperatures, being continuously monitored. Plant start-up, shutdown and duty selection are per-
:n ,: ooled
.3 Heaters
I katers
in compressed air driers and compressor oil '-alPs are either connected in balanced three-phase nks and supplied through electrically-held contactors 415 V three-phase 50 Hz or, for ratings up to ap-
859
Chapter 10
Mechanical plant electrical services
SIGNAL LINE PROM OfHER -RECEIVERS
r
APS 3
APS 2
I
TO DISTRIBUTION SYSTEM
APS
DUTY SELECTOR PRESSURE SWITCHES
TO 'DIRER COMPREBsoR s AND RECEIVERS
CCOLVG FOR OTHER COMPRESSORS
GENERAL SERVICE WATER
1—
FLOW I NDICATOR AFTERC O 0 LER
*-----
1)*
)
AIR I NLET
FILTER 0 FLOW I NDICATOR
I-
-0
SILENCER
UNLOAD IEDR
COMPRESSOR
SUCTION VALVES
orm■
MAIN AIR
— CONTROL AIR --- COOLING WATER
FIG. 10.39 General service compressed air system
860
Heating and ventilating plant d in the central control room and plant failure e displayed there. Control panels situated to the compressors house all the alarms, indica,ioro and controls necessary for the maintenance and ,:ontrol of the plant. vrne
I
tiarnis ar
When steam is available, it may be used as the heat source for the system, otherwise electrical heating is employed. The principal electrical requirements are outlined in the following sections. 12.2 Control gear
12 Heating and ventilating plant General description of plant 12.1 H ing and ventilation in a power station is provided :or die following reasons: T o protect equipment rooms, such as telephone ex• changes, during operation by creating a positive pressure in the room to prevent the ingress of airborne dirt. to ventilate equipment rooms, such as switchrooms, • and to maintain the air and equipment temperatures %vithin acceptable limits. • To ventilate equipment rooms where emissions during normal plant operation would create a hazard If allowed to collect, e.g., battery rooms. • To maintain a stable environment for sensitive equipment such as computers. • To ensure an acceptable working environment for pers onnel in offices, control rooms, etc. • To protect personnel from the effects of the accidental release of hazardous substances into the air during plant operation. • To provide a hot water supply. • To remove smoke in the event of a fire. [eating and ventilation systems are designed to suit the ,
pecific requirements of each power station. All use a
iiibination of air-conditioning units, filters, cooling a:r and extraction fans, water-chiller units, air dampers,
:oiorised valves and water heaters. The design requirements for heating and ventilation a typical power station are as follows:
The heating and ventilation system is supplied from a 415 V three-phase 50 Hz motor control centre. The switchboard and control panels are located adjacent to the heating and ventilation equipment, and accommodate the controls and instrumentation necessary for the automatic operation and maintenance of the system. Essential controls and alarms are provided in the central control room. 12.3 Classification of electrical equipment Electrical equipment is specified to either Categories I or 2 of CEGB specification US/12/50 [28] to suit the application. Category 1 is defined as equipment, malfunction or failure of which could be the primary cause of unwanted tripping or closing or the immediate loss of availability of primary equipment. Category 2 equipment is that which could have a direct or immediate effect on the operational availability of primary plant, if another abnormality exists or arises before the defect is remedied, or could cause operational inconvenience. The more stringent requirement of Category I is specified in areas where loss of heating and ventilation is not acceptable; namely computer rooms or, in nuclear stations, locations where either, (a), heating and ventilating equipment fulfils a function essential to the safety of personnel or to the reactor in the event of an incident, or (b), the failure of a fan or its standby could result in the loss of differential pressure which exists for the purpose of containing airborne contamination or the maintenance of clean conditions. Elsewhere Category 2 equipment is specified. 12.4 Drive motors
Temperature, ° C Relative max min hum i dity, t
o:tirol room
■
,
inpuier rooms ,
Imment rooms
( .,i‘le marshalling rooms •rtlerence rooms i ..N)ratories I !_ht workshops
workshops \14:ri
stores
22
1
0
Air changes per hour 3
8
45-55
22
18
-
45 55
27
22
18
12
—
10
45-55 _
22
1
8
40-60
17
22
1
8
40 - 60
7
_
18
_
—
15.5
_
—
13
_
2
2 2
In general, drives for fans, pumps, compressors and damper/valve actuators are 415 V three-phase 50 Hz squirrel-cage induction motors, suitable for direct-online starting. All motors are totally-enclosed and have a minimum degree of protection of 11 3 54. Those situated outdoors and exposed to the weather or situated in areas protected by waterspray fire protection, have a degree of protection of IP55 weatherproof. Motors driving contaminated air ventilation fans could, during routine filter replacement, be contaminated themselves. To minimise contamination in these circumstances, they have a degree of protection of IP55 and are capable of being totally overhauled onsite under strictly controlled conditions. 861
Mechanical plant electrical services
Chapter lc)
12.5 Air conditioning units Air conditioning units generally consist of a chiller unit, humidifier, airheater and fan,
12.5.1
Chiller unit
The chiller unit and air cooled condensers form a sealed refrigeration unit. Included in the refrigeration system is a compressor, dri‘en either through a flexible coupling or via a multiple vee-belt by a 415 V three-phase 50 Hz totally-enclosed fan cooled squirrel-cage induction motor. Hermetically-sealed motors are not used since they preclude maintenance. When oil sump heaters are used, they are supplied at 240 V single-phase 50 Hz.
12.5.2 Humidifier Steam generated by an electrode or electrically heated boiler unit, forming an integral part of the air conditioning unit, is injected into the air stream to increase humidity. Operation of the boiler is fully automatic upon demand from a humidistat located in the air intake.
12.5.3 Airheater A battery of electrical heater coils, heats the air progressively as it is drawn into the air conditioning unit and is automatically controlled by an inlet air thermostat in conjunction with a temperature controller. -
12.5.4 Fan A fan driven by a 415 V three-phase 50 Hz squirrelcage induction motor draws air through the air conditioning unit.
rated at 240 V single-phase 50 Hz and connected i n balanced three-phase banks with the star point brought out for operation on a 415 V three-phase 50 Hz four. wire supply. Each heater is provided with a spare three. phase bank of elements for use during maintenance o n the duty elements.
12.7 Cabling and terminations Each bank of heating elements is connected by flexible high temperature single-core cable to an adjacent ju nc tion box which forms the interface with the fixed cable system. The flexible cables have silicone rubber insulation and heavy duty oil-resisting and flame-retarda n t rubber sheaths to BS6007 Table 5 [29] allowing a
maximum continuous conductor temperature of 85 ° C. The cables are run in flexible conduit for protection.
12.8 Water circulating pumps Duty and standby pumps are provided to circulate water through each group of water heaters. The motor control scheme is arranged for manual selection of either pump for duty running and automatic selection of the standby unit in the event of failure of the duty pump. . A pressure switch in the inlet pipe to each water heater is connected to raise an alarm in the event of pump failure and to act as an additional plant inter-
lock to ensure that water heater elements cannot be energised under no-flow conditions.
13 Fire fighting equipment 13.1 General description of system
12.6 Water heating plant Water heating equipment uses electric immersion heaters complying with the relevant British Standards and the following requirements. Steel heater bodies are coated internally with an anticorrosive epoxy-resin coating to ensure a life compatible with that of the power station. Make up water is provided from a header tank. Each heater is provided with a pressure relief valve, an automatic air release valve, a water temperature indicator, inlet and outlet water isolating valves, a water drain valve, thermometer pockets in the inlet and outlet pipework, and water temperature thermostats to facilitate its commissioning and safe operation. Twin water thermostats are fitted — a self-resetting control thermostat and a manually-reset safety thermostat which is set to operate at a higher temperature to safeguard against control circuit failure. -
12.6.1 Heating elements I mmersion heaters are of the tubular-sheathed type, 862
Fire protection in a power station consists of the following systems: • Waterspray and sprinkler systems. • External fire hydrant system. • Fixed foam pipework system. • Fixed Halon 1301/system. 14alon 1301 bromotrifluoromethane (BTM) gas protection is installed in cable marshalling rooms, computer equipment rooms, instrumentation rooms and false floor voids below safety equipment. Each distri-
bution system is designed to supply BTM gas to the scene of the fire from storage cylinders, the system being initiated either automatically by heat or smoke detectors, or manually. Fixed foam pipework systems are provided to protect diesel and auxiliary boiler fuel oil tanks, diesel generators and transformers that are too remote to be served by the waterspray and mulsifyre systems. Foam generators are provided at each location. A
Fire fighting equipment raywater system, supplemented by hydrants, provides within the main equipment areas and a ,roteetionf fire hydrants covers those areas not provided o ternspraywater protection. ,h "; `"biesei_driven fire pumps supply water to a unk main. A separate fire hydrant ring tr ; i's. a:ue rpplied by a combination of electrically-driven sr r ji r " diesel-driven pumps , to provide security of supply. A"spraywater systems are divided into wet and dry system, pressurised water is contained ,,,ierns, In a dry . held closed by a compressed air ol valves, , contr 0 n incorporating heat or smoke detectors. Upon , er ic,e,:tion of a fire, air is released causing the control , a k e s to open and release water under pressure to the ,prinkler heads. A wet system is permanently filled with , oter , which is released by detectors incorporated in he sprinkler heads, upon the occurrence of fire. Dry ,„ re ms are commonly employed outdoors, where freezno temperatures are likely. ; Four categories of spraywater system are provided meet differing requirements; namely, waterspray, o and sprinkler. Waterspray is o rtsifyre, protectorspray intensity, fine spray system capable l a rge volume, high of emulsifying the surface of burning oil and is used auxiliary boiler houses, on turbine oil tanks and in other areas where oil fires may occur. Mulsifyre is ,i milar to waterspray but provides a less dense covera(je and is used on oil-filled transformers and oil Protectorspray is a low velocity water spray ,,,tem to protect plant from external fires, typical Sprinkler c samples being hydrogen storage vessels. systems are provided for the treatment of localised fires in equipment rooms, switchrooms and cable flats. Coal plant conveyors are protected by a separate dry - type sprinkler system. Control valves are main!ained in the closed position by a compressed air system as described above and opened by the release of air caused by a detector operating in the event of fire. Extraction systems are installed to remove smoke generated during a fire to facilitate access and minimise any damage which may be caused by its presence. This is particularly important in the event of cable fires ..,hich can generate large volumes of highly toxic and corrosive smoke. ,p
d
13.2 Controls and alarms The spraywater system, fire pumps and detector air
compressors are designed for automatic operation. Local control panels for the diesel-driven fire pumps accommodate all the equipment necessary for automatic operation, duty selection and manual control facilities. Plant status indications and alarms are displayed on the local panels and are wired from repeater
contacts to a fire control panel located in the central
control room.
The operation of a section control valve, as a result of one or more detectors operating due to a fire, raises
an alarm on the central fire panel and automatically
initiates a local audible alarm upon detection of water flow or loss of air pressure in the detector pipework. The alarm at the central fire panel identifies the location of the fire, allowing appropriate action to be taken to safeguard personnel and plant. Plant status and alarms associated with the electrically-driven detector air compressors, including low air pressure alarms, are displayed on the central fire panel. Low air pressure and loss of air pressure in the detector system are sensed and raised as separate alarms in order to differentiate between system faults (causing 'low pressure') and fires (causing 'loss of pressure').
13.3 Diesel-driven fire pumps Several diesel-driven fire pumps are provided, each of which is equipped with electrical starting gear and a 24 V battery. Normally operation is automatic, the pumps being started singly in sequence, initiated by pressure switches connected in the water ring main and set to operate sequentially as water pressure falls. When a fire occurs and water is discharged from the ring main, the pumps are started in sequence until the discharge flow is balanced by input and the ring main pressure is restored. Trickle- and boost-charging facilities are provided for each 24 V starting battery. In addition to the battery charger controls, the local control panel contains battery condition and charging indications, pump status indications and alarms, and manual starting controls. Manual starting controls and alarms are repeated on the central fire panel. Figure 10.40 shows the starting scheme for a typical diesel-driven fire hydrant pump. The design emphasis is to minimise the chances of the diesel not starting when called upon to do so. To this end, the design includes the following features: • Duplicate 24 V batteries and chargers. • Duplicate starting contactors. • Automatic starting with engine-cranking timer and repeat-start feature. • Automatic disconnection of cranking circuits when engine is running. • Remote and local manual start facilities.
13.4 Air compressors Automatically controlled electrically-driven air compressors are installed to charge the detector systems of dry installations. Compressors are started and stopped automatically to compensate for variations in detector pipework air pressure. Compressors are installed in pairs and are designated main and standby. Each compressor is controlled by a pressure switch connected in the air supply line from the compressor to the protection system. The main compressor is started first and the standby unit is 863
Mechanic& plant electrical services
Chapter 10
240V 1 Ph . 50H z
'Th/The —Y-
1
,
-
240/50-50V
The-rY1
RECTIFIERCHARGER UNIT 2
ECT IF IF RCHARGER UNIT I
-VE
-VE
*VE
-
MAIN
BATTERY
r• AUXILIARY I BATTERY
CRANKING MOTOR
LJl
AUTO START
MAIN STARTING
REPEAT START UNIT
0- 0
CONTACTOR
AUXILIARY STARTING gNTACTOR ....ryki F
MANUAL START 0 0
@®
L. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
I MANUAL START! I RELAY
■I■■
0
0 0
0
_ -----
---------
TEST START PUSHBUTTON
FAILED TO START
4
ENERGY START PUSHBUTTON
0 0 PUMP ON DEMAND
ENGINE RUNNING 1 r77: C
AUTO START RELAY
I
TIMER 0--.-
FAILED TO START_
o 01—
CRANKING TIMER
FAILED TO START RELAY ■imm1
0
`4.r•y^r^.
TIMER
ENG INE RUNNING SWITCH
0
ENGINE RUNNING RELAY
0
REMOTE/AUTO START SWITCHES (OPEN TO START)
FIWT 11.1
Flo. 10.40 Fire hydrant pump schematic diagram
864
PUMP ON DEMAND RELAY
Fire fighting equipment
broileht into service if the air pressure continues to motors are totally-enclosed fan cooled Dr i ve cage induction types supplied at 415 V three1 j .. Hz from contactor switchgear. -;0 13.5 Trace heating ,. ons o f p ipework and valve manifolds which may low temperatures during the winter are .„: ,pose d to lly trace-heated and insulated. Trace heating is i,:a TTlied at 240 V single-phase 50 Hz and is thermoontrolled as described in Section 5.2.7 of -
r
c
c hapter.
13,6 Detectors and distributors
Quartzoid bulbs I he bulb of a detector contains a liquid which has a point below any natural climatic figure and a rate of expansion with increase of temperature. •0 of vapour is trapped when the bulb is amount \ small .;:nrietically sealed. As the liquid in a bulb expands ..2,1er the influence of heat from a fire, the pressure in e bulb rises until the vapour is absorbed by the liquid tni bursting pressure is reached. When the bulb .I:atters, one of three actions occurs: 13.
6.1
,
• Fhe compressed air is released in a detector line to initiate operation of a water control valve, or; • 5. valve installed in the water pipework leading to the distributors is directly operated, or; • Water is released from a sprinkler.
Heat-detecting cables are of two types, integrating and non-integrating, and are supplied at low voltage from a control unit. The insulation resistance of an integrating cable decreases progressively as temperature increases whilst that of a non-integrating cable drops suddenly at a specified temperature. Reduction of the cable insulation resistance to that appropriate to the alarm temperature is sensed by a control unit which raises an alarm and initiates the spraywater system by transmitting an electrical signal to actuate the thermoelectric quartzoid bulbs. Heat-detecting cable continuity and supply integrity are monitored continuously and an alarm is raised on the central fire panel if either fails. 13.6.3 Smoke detection
Smoke detectors are of the point type, using scattered or transmitted light, or alternatively an ionisation cham-
ber. These devices are used on their own or in combination with heat detectors in areas such as amenity buildings, administration offices, workshops and stores where large scale, rapidly-propagating fires are unlikely. In these situations, the detection system is used to raise alarms and to locate the fire, enabling manual fire fighting equipment to be deployed and the buildings cleared of personnel. Ionisation chamber detectors consist of a chamber in which a radioactive source ionises the air and causes a small detectable current to flow between charged electrodes. The magnitude of this current is proportional to the level of ionisation within the chamber which is reduced by the presence of the particulate matter in smoke.
I iier moelectric quartzoid bulb sprinklers are similar those described above, but include a 'one-shot' . eator mechanism. An electrical signal from the ritrol cubicle of a heat-detecting cable system (see „tion 13.6.2 of this chapter) causes the actuator ,:,hanism to operate, shattering the quartzoid bulb .rsi releasing spray water. If the 'one-shot' actuator fails • operate, the bulb will burst under the influence of from a fire, as previously described.
Optical smoke detectors contain photoelectric devices which are sensitive to changes in the level of monochromatic light received either by direct transmission from the source or indirectly by scatter. Particulate matter in smoke varies the level of light falling on the photocell and hence the level of electrical signal flowing through the device.
13.6.2 Heat-detecting cable systems fear - detecting cable systems are installed extensively .Power stations in cable tunnels and cable flats, where ne nature of the materials installed requires that fire s detected' and treated with a minimum of delay to :nit the damage to plant and the danger to personnel. tnese systems respond far more quickly than is possible — mg conventional quartzoid bulb heat-detectors and 'nuke detectors. In cable installations, the heat-detecting cable is 'iNPended above the cables and under the cables im-nodiately above the floor to provide rapid response to "olh cable and external fires.
A common control unit supplies the smoke detectors at low voltage and monitors the level of signal continuously to detect any variation indicative of the presence of smoke at a detector head. To prevent spurious operation, a time delay of between 2 and 10 seconds is built into the alarm-initiating circuit. If the alarm condition exists at the end of the timed period, the control unit initiates audible and visible alarms locally and on the central fire panel and indicates the location of the detector head which has operated. Automatic supervision of detector electrical circuits and supplies is incorporated in the control unit. A typical smoke detector system is shown in Fig 10.41.
,
,
.
-
865
Mechanical plant electrical services
KEY
Chapter 10
RELAY
RELAY
BREAK GLASS CALL P DINT
I
0
7
r
DETECTOR OUTPUTS T0 FIRE PROTECTION SYSTEM FOR EACH ZONE
RELAY
OUTPUTS TO CCR FOR ALARM AND FAULT INDICATION POWER SUPPLY UNIT
24 V D C POWER UNIT
10 V A C
RELAY CONTROL UNIT
UNINTERUPTA8LE POWER SUPPLY
240 V
ZF ZF BELL RELAY — MONITORING — RELAY No I No 2 UNIT
21 V D C
240 V D C
ZONE 2
_J
LJ ZONE I
=ID
ZONE 4 ETC.
ALARM BELL ZONE 3 ALARM BELLS
DETECTORS AND CALLPOINTS (UP TO 32 ZONES)
FIG. 10.41 Smoke detection system
13.7 Fire dampers and smoke extraction
To prevent the spread of fire and smoke by ventilation and air conditioning systems, dampers are incorporated to shut off the ducts in the event of fire. These dampers are closed either electrically by the heat or smoke detection system, or mechanically by the operation of heatf usible links. They remain closed until manually opened when the fire has been extinguished. The dampers form 866
part of a smoke extraction system and are operated in conjunction with extraction and ventilation fans.
13.8 Control cabling Connections between control units, fire detector heads, control valves, manual alarm-initiating devices and other equipment essential for the operation of the fire
References systems are run in short-time rated firef cables. These cables are designed to remain proo 'functional for a minimum of twenty minutes in a test fi r e of 1000°C. Special attention is paid to the location d installation of these cables to prevent accidental an dama ge, and preserve their integrity in a fire, thereby uring that the operation of fire protection systems ens not jeopardised. is protect io n
13.9 Batteries and chargers In keeping with the high integrity requirements of fire protection systems, control supplies are derived from ", ..1 V lead-acid batteries operating in conjunction with aut omatic charging equipment. The chargers are supp li e d at 240 V single-phase 50 Hz and equipped with trickle- and boost-charging manual selection facilities, battery charging current and voltage indicators, local alarms and repeat contacts for raising alarms on the central fire panel.
14 References [II BS5000: Rotating electrical machines of particular types for particular applications
[21
554999: General requirements for rotating electrical machines
(31 BS5490: Classification of degrees of protection provided by enclosures 4 BS4683: Electrical apparatus for explosive atmospheres
1 1
151 555345: Selection, installation and maintenance of electrical apparatus for use in potentially explosive atmospheres 161 CEGB Specification EES (1980): General specification for electronic equipment — this specification succeeds EES (1970): and EES (1962) bearing the same title [
7
!
BS800: Specification for radio interference limits and measurement for equipment embodying small motors, contacts, control and other devices causing similar interference
181 BS466: Electric overhead travelling cranes [9]
BS88: Cartridge fuses for voltages up to and including 1000 V AC and 1500 V DC
[10]
BS5424: Control gear for voltages up to and including 1000 V AC and 1200 V DC
[11]
ESI Standard 37-1: 415 V AC switchgear, control gear and fusegear
[12]
BS3579: Heavy duty electric overhead travelling and special cranes for use in steelworks
[131 BS2655: General requirements for electrical, hydraulic or hand powered lifts (141 BS5655: Lifts and service lifts [15]
BSCP407: Electrical, hydraulic and hand powered lifts
[16]
BSCP326: The protection of structures against lightning
[17]
CEGB Specification US/76/10: Control and instrumentation; General technical requirements
[18]
BS417: Semiconductor rectifier equipment including transformers
[19]
BS 171: Power transformers
(20] British Electricity Board Standard BEBST2: Specification for transformers and rectifiers [211 BS2757: Classification of insulating material for electrical machinery and apparatus on the basis of thermal stability in service [22]
135159: Busbars and busbar connections
[23]
BSI58: Marking and arrangement of switchgear busbars, main connections and small wiring
[24]
BS6346: PVC insulated cables for electricity supply
[25]
BSCPI003: Electrical apparatus for use in explosive atmospheres of gas or vapour
[26]
BS4417: Semiconductor rectifier equipment including transformers
[27]
BS5967: Operating conditions for industrial process measurement and control equipment
[28]
CEGB Specification US/I2/50: General technical requirements for instrument and control equipment
[29]
BS6007: Specification for rubber insulated cables for electric power and lighting
867
CHAPTER 11
Protection 1 Introduction
8 Station transformer protection
2 Design criteria
9 HV/LV connections and generator voltage/HV circuit-breaker protection
3 Overall protection logic 4 Boiler protection 4.1 General 4.2 Low drum level or loss of boiler water 4.2.1 Steam/water mixture mass velocity 4.2.2 Steam/water mixture quality 4.3 Loss of feedwater flow 4.4 Loss of electric load 4.5 Methods of protection 4.5.1 Low drum level protection 4.5.2 Loss of feedwater protection 4.5.3 Boiler circulating pumps - unconditional signal 4.5,4 Sudden loss of steam demand {turbine trip) 5 Turbine protection 5.1 Turbine trips 5.2 Loss of lubricating oil pressure 5.3 Condenser vacuum low {exhaust pressure high) 5.4 Condensate conductivity high 5.5 Manual trip lever 5.6 Overspeed trip 5.6.1 Choice of interlock 5.6.2 Setting of the low forward power relay 5.7 LP exhaust steam temperature high 5.8 Loss of electric governor 5.9 Low steam inlet temperature and pressure 6 Generator protection 6.1 Stator earth faults (low impedance earthing) 6.2 Stator earth faults (high resistance earthing) 6.2.1 Current transformer requirements for protection using relay R1 6.2.2 Matching transformer 6.3 Stator phase to phase faults 6.4 Stator turn to turn faults 6.5 Negative phase sequence 6.6 Loss of generator excitation 6.7 Pole slipping 6.8 Loss of stator water flow 6.9 Hydrogen temperature high 6.10 Hydrogen/stator water cooling flow 6.11 Excitation failure 6.12 Motoring of the generator 6.13 Emergency pushbutton 7 Generator transformer and unit transformer protection 7.1 Phase to phase and earth fault protection 7.2 Generator transformer HV inverse time and high set instantaneous overcurrent 7.3 Unit transformer HV inverse time and high set instantaneous overcurrent 7.4 Standby earth fault 7,5 Generator transformer and unit transformer internal faults 7.6 Winding temperature 7.7 Conservator 'low oil level' alarm 7.8 Pressure relief device alarm 7.9 Freezer air drier alarm 7.10 Overfluxing 868
9.1 Phase to phase and earth faults 9.2 HV circuit-breaker faults 9.3 Generator voltage circuit-breaker or switch disconnector 10 Pumped-storage plant protection 10.1 Dynamic braking overcurrent protection 10,2 Under frequency protection 10.3 Over frequency protection 10.4 Overspeed in excess of 10% 10.5 Loss of pumping power 10.6 Emergency stop pushbuttons 10.7 Overvoltage 10.8 Excitation equipment protection 10.9 Stator cooling air over-temperature 10.10 Bearing temperatures and oil levels 10.11 Back to back starting protection 10.11.1 Generator runaway 10.11.2 Incorrect excitation levels on the generator-motor 10.11.3 Excess heating of the stationary field winding in the event of a failure to start of generator-motor 1 0.12 Excitation transformer 10.13 Station transformer 1 0.14 Starting transformers 1 0.15 Starting equipment 10.16 Protection during starting 1 0.17 Protection of the pump-turbine and the upper/lower reservoirs 1 0.17.1 Category A trips 1 0.17.2 Category B trips 11 DC tripping systems 11.1 Logic diagram 11.2 Tripping schematic diagram 11.3 Trip supply and circuit supervision 11.4 General comments on the tripping arrangements 12 Auxiliaries systems 1 2.1 Operating criteria 1 2.2 Protection requirements 1 2.3 Auxiliary transformers 1 2.3.1 Phase to phase and earth fault protection 1 2.3.2 Winding faults and transformer overloads 1 2.3.3 HV inverse time and high set instantaneous overcurrent 1 2.3.4 Standby earth fault 1 2.4 Auxiliary generators 12.4.1 Mechanical trips 12.4.2 Electrical protection 12.4.3 Gas turbines 12.5 Motors 12.5.1 Motor circuits at 415 V (contactor circuits) 12.5.2 Motor circuits at 11 kV and 3.3 kV 12.5.3 Thermal overload relay 12.6 Cables 12.7 Busbar protection 12.8 High breaking capacity (NBC) fuses 12.9 Protection co-ordination
Introduction 1 2.9.6 Discrimination 1 2.9.7 Techniques to obtain close co-ordination between protection stages 1 2.9.8 Application to a typical system
Characteristics of 415 V fuses 12.9.1 12.9.2 Characteristics of inverse time relays 12.9.3 Characteristics of definite time relays • 12.9.4 Characteristics of thermal relays
13 Reliability
2.9.5 Calculations
1 Introduction I he poNer station generating system basically comprises cow- main plant areas (Fig 11.1): seam raising plant (steam generator) or, for hydro • ,:ations , a water supply and/or storage system. •
A steam or water turbine.
• 3, g enerator.
• Step-up and step-down transformers, switchgear and connections. The last equipment connects the generator to its loads. A small percentage of the power (5 to I0 07o, approximately) provides services inside the power station (this auxiliary system is dealt with in Chapter 2), the remainder goes to the transmission network. It can be seen from Fig 11.1 that the power station system is
*TRIPPING SYSTEM
*TRIPPING SYSTEM
SEND AND RECEIVE TRIP SIGNALS
4 STEAM GENERATOR
2
TURBINE
GENERATOR
TRANSFORMERS SWITCHGEAR CONNECTIONS
TRANSMISSION SYSTEM
STATION AUXILIARIES FUEL SUPPLIES . LUBRICATING OIL SUPPLIES RECTIFIERS HEATERS MOTORS . VALVES
STATION AUXILIARIES ELECTRICAL SUPPLY SYSTEM
*TRIPPING SYSTEMS 1 AND 2 CONTAIN UNIT TRIPPING LOGIC SHOWN IN FIG. 11,2
Flo. 11.1 Overall generating protection scheme
869
W"' Protection very closely interconnected, so that a single failure requires more than the disconnection of the faulted plant, both electrically and mechanically. This chapter deals with: • The electrical and mechanical protection of the plant items for which faults result in the tripping of one of the main plant items (main unit protection). • The protection against electrical faults in the auxiliary system (auxiliary system protection). • The methods adopted to initiate the tripping of the other associated main plant items. For completeness, individual plant protection systems, both mechanical and electrical, are explained and, where explanations are to be found in other chapters concerned with that plant item, reference is made to those chapters. Included in the sections dealing with the protection of transformers, are the generator transformer, the station transformer, the unit transformers, together with their main electrical connections, switchgear and disconnectors (isolators). In nuclear power stations, the station transformer has become another unit transformer and the level of protection has been raised to that of the unit and generator transformers, irrespective of the supply voltage. Details of the relays used today are given; in particular, where electromagnetic types have been replaced by digital, but with the developments in digital relay design, protective systems employed by the CEGB are continually changing. When digital unit protection systems were introduced in the late 1980s, protection schemes changed from two trip channels (1 out of 2) to three independent protection systems, each providing protection such that failure of one would neither cause nor prevent a trip. This improved reliability and provided the facility for on-load testing from the electrical trip initiating device to the turbine stop valves. This is explained in Section 11 of this chapter on DC tripping.
2 Design criteria Before describing the individual protective systems, certain design criteria have to be established. Generally the protection system is designed so that if faults occur, the faulty plant is disconnected, whilst continuity of supply from the generators is maintained, consistent with system stability. Listed below are major requirements on which protection selection and settings are based:
Chapter 11 • Faults which are not cleared by the faulty item's ow n protection, will be cleared by secondary or backup protection. • Protection of plant is designed to match as clo se l y as possible the plant operating characteristics, e.g,, negative phase sequence protection is designed to match the generator thermal withstand to negati ve phase sequence currents. • in general, protection systems should be designed so that no single failure of a protective device cause s a trip or permits a fault to remain connected to the system. The exception is where the reliability of the protective system is such that failure to trip is not considered credible, i.e., where equipment is installed in controlled temperature and humidity conditions and is fully dust-proofed. This applies particularly to electrical protection systems employ. ing electromagnetic relays where risk of malfunction is very low. All other protection devices, such as plant-mounted tripping devices, employ systems of at least 'two out of three'. It is likely that the compactness of digital relays will encourage full redundancy to be built into electrical protection as well. • To facilitate testing or fault investigation with the generating unit on-load and one of the tripping systems isolated, the allocation of the output contacts of the protective relays must be such that the operation of any one relay does not cause tripping of more than one tripping system. • Standing trip conditions when the generator unit is out of service must be avoided. For example, turbine and generator mechanical trips which would remain operated after the unit has been shut down are removed by normally open pressure switches mounted in the turbine hydraulic fluid pressure system. • The facilities associated with a tripping system shall be physically segregated from the other tripping systems as far as is practicable, by using separate relay panels, separate terminal blocks in marshalling and terminating cubicles, and diverse routing of secondary cables. • The detailed electrical connections for the protective relay circuits have to be in accordance with the appropriate CEGB Standards.
3 Overall protection logic
• Faults on plant items must be disconnected as quickly as possible to minimise damage.
An overall protection logic diagram typical of nuclear stations is shown and described fully in Section 11 of this chapter, together with the tripping schematic developed from it. The role of the unit protection is:
• The protective systems shall be stable for faults outside the protective zone.
• To accept protection tripping signals from each of the main plant items numbered 1 to 4 in Fig 11.1.
870
Boiler protection • To bring as many of the main plant items as necessary to a safe condition by means of a tripping logic. E.ich or the main plant items has its own protection ,teni and a typical turbine protection system (item 2, , ■ 11.0 is shown in Fig 11.2. Operation of any one - he protection devices shown, operates a trip reof t trip the unit protection. The unit protection (0 therefore receives the same trip signal for several different fault conditions sent to each of its tripping of which there are two at present. Two types signal can be received from the turbine, low vao' f uurn is Group 2 and all others are Group 4. The ,.: i.nifieance of the groups is explained in Section 11 of
his chapter. Electrical fault protective relays for the generator and its associated transformers and connections, are housed in the same relay room as the unit protection relays and therefore each relay directly trips into the unit protection trip relays. This avoids additional delays due to interposing trip relay operation, which is vital for electrical faults which must be cleared as quickly as possible. Speed of tripping is not so critical for boiler, turbine and generator mechanical faults, where usually delays of several seconds can be tolerated. 4 Boiler protection
4.1 General Faults can occur on a boiler or its auxiliaries which an be isolated without a boiler trip, i.e., on motors, cables, actuators, etc., and for information the reader is referred to Volume F on control and instrumentation. For those which require a trip of the boiler (either immediately, or on completion of a sequence), a signal is also given to trip the turbine followed by the remainder of the unit. It is one of the functions of the unit protection to ensure that plant items are tripped in the correct order, e.g., the high voltage circuitbreaker is delayed and not tripped before the turbine stop valves have closed. The logic of sequential tripping is shown in Fig 11.35. A unit tripping interface is provided for a number of boiler operation problems which if not dealt with would lead to damage. These are associated with feedwater or steam supply abnormalities.
4.2 Low drum level or loss of boiler water If drum water level falls below a certain level, there is a danger of departure from nucleate boiling, which is when the bubbles of steam form a homogeneous solution and are continually breaking away from the walls of the furnace tube. A departure from this condition occurs when the steam forms a blanket on the Inner surface of the tube and results in a decrease of
the heat transfer coefficient by the order of a magnitude or more. This produces a rise of tube metal temperature, the magnitude and rate depending on tube thickness, tube material and local heat flux. The increase of metal temperature may cause furnace tube failures due either to diminished material strength or to increased on-load corrosion, but each incident reduces tube life. The local heat flux at which the departure from nucleate boiling occurs is defined as the critical heat flux and is a function of operating pressure, tube diameter, tube orientation, mixture mass velocity and mixture quality. In a given boiler, operating at a given pressure, the only variables that affect departure from nucleate boiling are steam/water mixture mass velocity and steam/water mixture quality. 4.2.1 Steam/water mixture mass velocity In assisted circulation boilers, steam/water mixture mass velocity can only be altered from the normal
operating value to an appreciable extent by the failure of one or more of the circulating pumps. The protection is described under loss of feedwater flow in Section 4.3 of this chapter. For natural circulation boilers, the steam/water mixture mass velocity is not significantly altered from its normal value by any of the operating variables other than the steam/water mixture quality. 4.2.2 Steam/water mixture quality
Steam water mixture quality is affected by drum water level, since this affects the efficiency of separation of steam and water and hence the risk of departure from nucleate boiling. The lowest drum level at which the above condition occurs is determined for each boiler and a unit trip is initiated when the load drops to this level. At a level above this, an attempt is made to prevent the water from reaching the trip level by an emergency start of the starting and standby electric feed pumps.
4.3 Loss of feedwater flow Loss of feedwater flow produces a rapid fall in drum level which, as stated above, causes a departure from nucleate boiling when a certain level is reached. In some boilers, this will not lead to a dangerous situation at a drum level higher than that detected by the low drum level protection. A unit trip from loss of feedwater has not been required on units since 1974. The length of ti me that it can be allowed to persist depends on circulation margins. The need for inclusion of detection of loss of feedwater in the system of protection against departure from nucleate boiling therefore depends on the characteristic of the particular boiler and auxiliaries, and is determined for each application of the protection system. 871
Protection
0
1I
Chapter 11
AUXILIARY TRIP CIRCUIT 1
OV
PS4
''CV
RL7
RL23
R L 16
_ r‘r^,Th
pS-
RL
RELAY .ftuo
CATEGORY
4
A
1
RDS3
R1_ 0
STATOR
010
PLI
COOLANT LSW5
CONDENSER LEVEL P
_ J
RL64 y4
S' LuBRICATING OIL
AL24
.
CATEGORY
GOVERNOR FAIL
RL67 _
AUXILIARY TRIP CIRCUIT , RELAY PLA,10 > PRESSURE SWITCH INTERTIP,P CEFECTIvE
Oj
1
RL73
AUXILIARY TRIP CIRCUIT 2
ICY CI
PEE R1_17 --01.15--*---1■0
R0 L
JRL14
Rsa RELAY FLUID POS4
CATEGORY
RES
SL It
STATOR
4Ih rOOLANT 0 I 0 LSW6
CONDENSER LEVEL
J CATEO0FIY
a
0
D 620___fy
GOVERNOR FAIL
re
ID
ALS9
AUXILIARY rpp CIRCUIT 2 PRESSURE SWITCH iNTERTRiP DEFECTIVE
CI RL73
AUXILIARY TRIP CIRCUIT 3
- -
JR1.16 CATEGORY
ALE
RELAY FLU 1O RL12
POSE
STATOR * COOLANT I 0 ■Imp CONDENSER LEVEL
RL30 LSW7
RC66
_ .45LA BREATiNo ofi_ ca GOVERNOR FAIL
L
J
,_7Aca,32
CATEGORY
B
D0630___ n°.... ALSO
RL69 L
-
—
1
to r
*
oI
FIG. U.2 Typical turbine protection system 872
ol: RL 73
XILIARY TRIP AUXILIARY
}
CIRCuIT 3 RELAY FLJID PRESSURE SWITCH IN l' EP TRIP DEFECTIVE
Boiler protection
751PP , NO SYSTEM I RL5 -
-
1
RL2 0 0 O-
RL I
I 5L 3 -
0■••••••■■0
■ri
5L2
■If
11 L3 o•
-■
RI.;
RL3 _ —
ILP13■NE SOLENOID TRIP SUPER v ■ SJC.1.4 SLAM.,
RL
aL:d
RL52
RL3 —4,—.10
RL
TURBINE TRIP SOLENOID'
°
RL6I COIL A
,
TRIPPING SYSTEM 2
0
,■•■•
RL2 0 Q.
PL P-0 0 ALSO
RL40
••■■
RL2 0-0
ov
RL3
Pi_ 52 COIL
I1L52 COIL A 0
Cra■,
R1.52 COIL 8 0 RLd
RL 52 COIL 8
—•
RLS8
RL3
.■1
ALl
ALT
TURBINE TRIP SOLENOID 2 TRIP SUPERVISION ALARM
FIL5
PIL6 cd
0...—■;) ALA
RLS
IMMIN1
AL9 --4■■•-0 0
■••■
,mwm 1
RL7 I
(IE TRIP =11 TI R1 37 SOLENOID 2
Cy'ri RL 52 COIL A
F. / G.
4.4 ,
11.2 (coned)
Typical turbine protection system
Loss of electric load Ram demand is lost due to the toss of electric load,
(ripping of the turbine emergency stop valves and ..0 ,.crnor stop valves is initiated. Overheating of the ‘uperheater and/or reheater tubes, due to the cessation 't steam flow, occurs rapidly unless the firing is :minguished or reduced to a very low level. 4
5 Methods of protection
rhe Various abnormal operational states already men-
tioned are detected by the various devices described below. These shut down the unit plant, as described earlier in Section 3 of this chapter.
4.5.1 Low drum level protection Low drum level protection uses spare contacts on the relays contained in the Hydrastep water level gauge equipment that is used to indicate the drum water level (see Fig 11.3). To avoid spurious trips, these trip signals have to be validated by separate water level tripping gauges. Identical Hydrastep water level gauges are 873
Protection
Chapter
A SIDE
SIDE
fx
A POWER SUPPLY SOURCE
I. EU
irm
I.
am -MEM
U. STEAM
TIMM WATER
U. DISPLAY UNIT
FIG. 11.3 Four-vessel Hydrastep system block diagram
874
POWER SUPPLY SOURCE 'Y .
-
IP-
Boiler protection fitted at each end of the drum to improve reliability a nd to indicate the water level at each end of the drum. The gauge pressure vessels are connected to the drum by pipes and valves, such that they represent extensions of the drum and hence contain the same water level as the drum, within the limits created by density error and pressure drop due to condensate flow. The connection of the vessels to the drum is shown in Fig 11.4.
The operation of the Hydrastep water level gauge system depends on the difference in the electrical resistivities of pure water and steam under operating conditions, which is two, or more, orders of magnitude. Therefore, by making resistivity measurements at a number of points arranged vertically in a pressure vessel attached to the boiler drum, it is possible to say, at any level, all measurements above represent steam
7
STEAM SIDE CONNECTION
CONDENSATE WEIR
BOILER DRUM AuGE.
N L
GAUGEGLASSES
LONG RANGE LEVEL TRANSMITTER
a
a) Typical gauge-glass remote level transmitter connections at boiler drum. Twin gauge glasses used to give a wider range of measurement for chemical clean and steam purge
WATER SIDE CONNECTION
TRANSMITTER
STEAM CONNECTION STUB / STEAM INLET NON•FtETURN VALVE STAINLESS STEEL BALL PRESSURE VESSEL BODY DENSITY
13 5
DIFFERENTIAL PRESSURE TRANSMITTER
LEVEL SIGNAL
ELECTRONIC DENSITY COMPENSATOR
PRESSURE SIGNAL
PRESSURE TRANSMITTER
Hydrastep system pressure vessel
FiC. 11.4 Connection of a ilydrastep vessel to the boiler steam drum
875
1P"'" Protection
Chapter 11
(high resistivity) and all measurements below represent water (low resistivity). Figure 11.5 shows a resistance measuring cell. Each vessel has 12 electrodes mounted along its length, and the resistance of each electrode is measured between the electrode and the vessel wall to determine whether there is steam or water at that level. Level is indicated by means of coloured lamps; green for water and red for steam (Fig 11.3). The signals derived from each resistance cell operate a changeover relay whose contacts operate the coloured lamps and provide signals for tripping and alarm purposes. The additional validation pressure vessels at each end of the drum provide extra security for tripping purposes. Whilst the main level indication contains 12 electrodes, the validation pressure vessel has only six to cover the range around the trip level. The time between detecting a !ow level and internal damage to the boiler is about 14 seconds at full load. Both gauges at the same end of the drum must be detecting a drum level below the trip level before a trip is initiated to the boiler firing trip relays. Allowance is also made in each gauge for a faulty level indicator by checking that the electrode above is also detecting a low level. This checking is carried out in the logic unit shown on Fig 11.3. Operation of the Hydrastep system at one end of the drum or the other, will either trip the boiler firing trip relays to trip the boiler firing, or trip the boiler directly from its own protection. 4.5.2 Loss of feedwater protection
Figure 11.6 shows a simple representation of a feedheating system. It is not representative of any parti-
ELECTRICAL IL CONNECTION TO DETECTOR
RETAINING NUT
cular system but illustrates the extent of the loss of feedwater protection. Steam from the boiler is supplied to the HP turbine via stop and governor valves. Exhaust steam from th e HP turbine is returned to the boiler for reheating. It is then fed through similar valve arrangements into an IP turbine and thence to LP cylinders. From the LP cylinder, the steam passes through condensers and the condensate is then pumped by a n extraction pump through a series of heaters, to raise its water temperature, and back to the boiler. On the outlet side of the heater chain, it is current practice to install two electrically-driven feed pumps and one steam turbine driven pump, the turbine being fed with steam bled from the main turbine; although future plant may omit the steam turbine driven pump. Protection is provided to detect a loss of feedwater caused by the failure of one or two emergency feed pumps or the main turbine driven feed pump. The protection operates as follows. Two time intervals t 1 and t2 seconds have to be determined, ti being the time between the detection of loss of feedwater and the onset of departure from nucleate boiling for unit loads above the maximum corresponding to the output from one electric feed pump, t2 being the time taken at lower loads. The time intervals ti and t2 have to be determined for every application of the protection to a particular boiler/turbine feedheating system. For loads below the output of one electric feed pump, the protection can be omitted if t2 is of sufficient duration to ensure that adequate protection is provided by the low drum level protection. Figures 11.7 and 11.8 show typical schematic diagrams for one or two standby electric feed pumps. The loss of feedwater is sensed by measurement of differential pressure across each pump discharge nonreturn valve (NRV). Duplicate transmitters are provided across each NRV (A and B in Figs 11.7 and 11.8). Each transmitter drives a trip amplifier which is set to a differential pressure consistent with the boiler design and they are arranged to meet the following conditions:
• One turbine feed pump in service — load in excess CLAMPING PLATE
PRESSURE VESSEL BODY SEALING JOINT
CERAMIC INSULATOR
ELECTRODE TIP
RESISTIVITY CELL
FIG. 11.5 876
iiydrastep resistance measuring cell
of that met by one electric feed pump capacity. On detection of loss of feedwater from the turbine feed pump, a conditional 'loss of boiler water' trip is automatically initiated and will be effected, unless two electrical feed pumps are installed and both are run-up and delivering within t1 seconds (Fig 11.7). • Turbine feed pump in service — load not in excess of that met by one electric feed pump. On detection of loss of feedwater from turbine feed pump, a conditional 'loss of boiler water' trip is automatically initiated and will be effected, unless at least one electric feed pump is run-up and delivering within t2 seconds. • Two electric feed pumps in service — load in excess of that met by one electric feed pump (Fig 11.7).
GENERATOR
EXTRACTION PUMP
GLAND STEAM CONDENSER
TWO ELECTRICALLY DRIVEN BOILER FEED PUMPS -- MAIN EAM SUPPLY
- REHEAT/BLED stEAm HP HEATERS
FEEDWATERICONDENSATE DRAINS
Vici, 11.6 A simplified feedlicaling sysiem
LP HEATERS
uopoalo)dJapoe
-
'19111P Protection
Chapter 11
CHANGEOVER ON LOAD GREATER THAN 12 MCR 0 0
HV CB AUX SWITCH
—ro
0
01Lo
BOILER PRING TRIP RELAY
t
0 0—
.
EED PUMP '. NRV C P
A
CONTACTS CLOSE ON HIGH REVERSE DIFFERENTIAL PRESSURE
'NS
TIME DELAY REL A st
A
EMERGENCY PEED PUMP NRV D.P
c-r
,
The-VM
TIME DELAY RELAY
A
EMERGENCY FEED PUMP EMERGENCY START RELAY
A
= LOAD THAT CAN BE MET WITH EMERGENCY FEED PUMP
Flu. 11.7 Loss of feedwater protection for a system using one electric feedpump The scheme shows the turbine feed pump time delay with two sets of contacts which operate after ti and t2 seconds. An alternative scheme may be adopted using a separate time delay for each time setting.
On detection of loss of feedwater from either one or two of the electric feed pumps, a conditional 'l oss of boiler water' trip is automatically initiated and will be effected, unless the turbine feed pump is run-up and delivering within t1 seconds. • One or two electric feed pumps in service — load not in excess of that met by one electric feed pump capacity. On detection of loss of feedwater from one electric feed pump, a conditional 'loss of boiler water' trip is automatically initiated and will be effected, unless the other electric feed pump is delivering rated flow, or the turbine feed - pump is trailing and is brought manually to rated delivery within t2 seconds. During start-up, the boiler is protected against a low drum water level by the 'drum level' low trip and the feeciwater trip is vetoed for the following reason. On initial light-up, the electric feed pump may not be required to deliver feedwater to the drum and will not be put into service until it is required later on. This is so because some units are able, during initial light-up, to generate sufficient steam for a supply to the turbine feed pump to enable it to meet feedheater requirements. In these circumstances, it is necessary to veto the trip initiation from loss of feedwater in order to avoid a permanent boiler firing trip being established. 878
The 'loss of feedwater' trip is therefore conditioned by the generator HV circuit-breaker, as shown in Figs 11.7 and 11.8, to remove the trip whenever the generator is on open-circuit. Under these circumstances, the boiler is protected against a low drum level by the low drum level' protection. 4.5.3 Boiler circulating pumps — unconditional signal
On boilers which require forced feedwater circulation between the drum and the boiler furnace, all available boiler circulating pumps are operated at all loads. The boiler system is designed such that full load can be met using three out of four circulating water pumps (Fig 11.9). Therefore the minimum number for avoidance of a trip is dependent on whether the unit load is above that at which at least three pumps are required. When the boiler is operating at loads above this level with only three pumps in operation, the loss of a further pump will automatically initiate an unconditional 'loss of boiler water' trip. When the boiler is operating at or below this load with only two pumps running, the loss of one of these pumps automatically initiates an unconditional 'loss of boiler water' trip. The scheme shown in Fig 11.9 satisfies these trip requirements:
Turbine protection
0 HV CB AUX SWITCH
BOILER FIRING TRIP RELAY
..■■■■
A 'A' EMERGENCY FEED PUMP NRV O.P. CONTACTS CLOSE ON HIGH REVERSE DIFFERENTIAL PRESSURE
TIME DELAY RELAY
A
A
'B' EMERGENCY FEED PUMP NRV D.P. TIME DELAY RELAY
B
EMERGENCY FEED PUMP EMERGENCY START RELAYS
L'.= LOAD THAT CAN BE MET WITH 2 EMERGENCY FEED PUMPS
FIG. 11.8
Loss of feedwater protection for a system using two electric feedpumps
4.5.4 Sudden loss of steam demand (turbine trip}
This form of protection applies equally to conventional and nuclear plant. The control of the turbine steam valves is by a fluid pressure system which holds the valves open against a Spring load. Release of this pressure operates pressure switches in the fluid system. Referring forward to Fig 11.36, which shows a tripping scheme for nuclear plant; operation of the pressure switches via time delay relay TDR1 contacts, operates trip relay 7, which sends a Signal to trip the steam generator. If any of the 400 kV disconnectors or circuit-breakers are open, then TDR1 is de-energised and prevents a trip of the steam generator when the turbine-generator is not connected to the transmission system. This allows for a turbine trip when the generator is off-load without tripping the steam generator. The time delay provided by TDR1
ensures that tripping of the steam generator is not prevented by opening of the circuit-breaker from a unit trip, which sends a trip to the turbine and the circuit-breaker at the same time. By tripping the steam generator following a turbine trip when the generator is on-load, its tubes are protected against overheating. Excess steam will exhaust to atmosphere. It is to be noted that if the generator is deloaded and a steam generator trip is not required, the operator must open the generator circuit-breaker first before tripping the turbine.
5 Turbine protection As with the boiler, faults can occur on the turbine and its auxiliaries which can be isolated without tripping the turbine: Volume C, Chapter 2 'Turbine plant systems' 879
Protection
7PP 3 .;PPLY .
F C.'
CLCSE ;A•EArLA
Chapter I w - EP
-
-1 7. •
ANI
X
, -2.4a,
sjaPLY 0
mcn
Pi,MP A
5.
5C r
o
PIP C CSV
DUMP C 0 9.
ro 01
SW
PUMP '0• 0 P SW
valve actuators, and diverting the fluid remaining i n the actuators to flow to drain. Volume C, Chapter 2 describes the system in detail, but the basic operation of the hydraulic control system is as follows. Fluid pressure is required to hold the turbine sl op and governor valves, which control the steam suppl y to the turbine, open against spring pressure, in th e absence of fluid pressure, the springs close the steam valves. Hydraulic control fluid is supplied to the ste am valves via two emergency trip valves, and the turbine is tripped by the operation of either of these valve s diverting the hydraulic fluid to drain. The trip plunge rs in the emergency trip valves are held in the clo se d position by means of a spring which is held corn. pressed by a trip latch. This latch is released either by energising the trip solenoid or by acting directly on the trip latch from the overspeed bolts or the manual trip lever. This causes the emergency trip valve to op en , isolating the supply of hydraulic fluid to the turbine valve operating gear, and putting the hydraulic fluid to drain, with consequent loss of fluid pressure and closure of the main steam valves.
UX OW
▪ JP=P 0 CO ;DS
5.1 Turbine trips
A
The following turbine protection devices trip the turbine; • Loss of lubricating oil. • Condenser vacuum low (exhaust pressure high). • Condensate conductivity high. • Manual trip lever. • Overspeed trip. • LP exhaust steam temperature high. • Loss of electric governor. • Low steam inlet temperature and pressure.
BOILER TIRING TRIP RELAY
Flo. 11.9 Loss of boiler water protection against failure of the boiler circulating pump
identifies these. All unit protection devices which trip the unit, are arranged to work directly into each emergency trip valve tripping circuit (Fig 11.10). This applies to all faults where serious damage could occur before an operator could take corrective action. The philosophy is applied, hearing in mind the need for maximum availability and the need to limit automatic trips, to those where there is insufficient time for the operator or control system to take corrective action. The turbine is tripped by interrupting the supply of hydraulic control fluid to the turbine main steam 880
They are typical of modern plant. A full description of the systems is given in Volume C, Chapter 2. The turbine trip systems are designed to give full redundancy of trip initiating devices (Design criteria, Section 2 of this chapter) and on-load testing up to the emergency trip valves. Weekly on-load testing of the turbine emergency trip valves is essential as part of the procedure to avoid an uncontrolled overspeed of the turbine for failure to close the main turbine stop valves. On-load testing is done by isolating each emergency trip valve solenoid in turn and using the protection devices to operate the isolated trip valve.
5.2 Loss of lubricating oil pressure The fluid for operating the turbine valves, forms a separate system from the lubricating oil system. The oil in the lubricating system is circulated by a centrifugal type pump, directly driven from the turbinegenerator shaft (Fig 11.11). This pump receives oil under pressure from an oil-turbine-driven boost pump and delivers
Turbine protection
INTERPOSING Ra
UNIT PROTECTION 1NTERTRIP RECEIVE T R 1 0•4‘. mu,
INTERPOSING R5
INTERTRIP RECEIVE TR2
•
.1110' • TRIP RELAY 1 • TRIP
RELAY 2
MII• • TRIP RELAY 3
SOL
.11,' •
I
RIP RELAY .110' •
I
TRIP RELAY 5
SOLENOID
•
cIROuiT SUpERvisoN
TRIP RELAY 6 WI,' • UNIT TRANSFORMER TRI
U
MIP• • UNIT TRANSFORMER
TR2
I
MO' •
TURBINE TRIPPING SYSTEM 1 SEE FIG 11 2
SOLENOID CIRCUIT SUPERVISION
FIG. 11.10 Emergency turbine trip valve — typical tripping circuit
oil by way of the oil turbine to the turbine-generator bearings. The main oil pump also delivers oil direct to the generator hydrogen seal oil system. Pressure drop through the oil turbine reduces the oil pressure to that required for the turbine bearings. The oil turbine is mechanically coupled to the boost
pump, which has its suction flooded in the main oil tank and. delivers ail to the main oil pump inlet. An oil tank ounted m AC motor-driven lubricating oil pump is also provided to supply oil to the turbine-generator bearings during run-up and rundown of the unit. Falling lubricating oil pressure to the turbine-generator bearings automatically starts the AC motordriven lubricating oil pump. If this pump fails to start, or completely loses its pumping, further reduction in oil Pressure to the bearings will cause a DC motor-driven oil pump to start automatically and, at the same time, a turbine-generator trip is initiated.
Turbine tripping is initiated directly by loss of lubricating oil pressure. Duplicated spring-loaded trip cylinders in the front pedestal are pressurised by the lubricating oil pressure. On loss of bearing oil pressure, oil is released from the trip cylinders, and mechanical linkages displace the trip latches of the duplicate trip gear. This causes the emergency trip valves to operate. Tripping is delayed by the action of a deadweight accumulator which maintains minimum supply pressure during transient pressure fluctuations. Each trip can be on-load tested. 5.3 Condenser vacuum low (exhaust pressure high) Each of the two direct-acting vacuum trip units consists of two sensing elements. Each of the four elements compares condenser vacuum with absolute vacuum, and 881
Protection
Chapter
SHAFT DRIVEN MAIN OIL PUMP SEAL OIL SUPPLY VAPOUR EXTRACTOR
Hi
PRIMING LINE
11
TURBINE BEARING DRAINS
BEARING OIL SUPPLY
I
I
I
GENERATOR REAR BEARING E.,`RA.N
LOOP SEAL OIL TANK
COOLER BYPASS VALVE
PRESSURE REGULATING ORIFICE
■•■■■•■=4
TRIMMING VALVE
FULL FLOW DUPLEX FILTER
VAPOUR EXTRACTOR OIL TURBINE
RETURN OIL STRAINERS TO JACKING (DLL PUMPS
2x 100% OIL COOLERS
ZIE*111L■
":( 14 MAIN OIL TANK
- TO PURIFIER OIL TURBINE DRIVEN BOOST PUMP FIG.
1
A.0 MOTOR DRIVEN LUBRICATING OIL PUMP
i1.11 Lubricating oil system
both elements of either unit are required to sense low vacuum before direct tripping of the turbine can occur. The turbine tripping is initiated when either of the low vacuum trip units senses tow vacuum and, by direct mechanical action, causes lubricating oil to be released from a corresponding trip cylinder (same one as for lubricating oil). This then causes the corresponding emergency trip valve to operate. The system can be on-load tested by admitting air to its sensing elements: this includes operation of the trip valve. Operation of a by-pass interlocking valve prevents operation of the main stop valves. This valve has to be in the by-pass position before on-load testing can. be carried out. The above arrangement causes a trip of the unit by fluid pressure switches in the hydraulic control fluid supply to the emergency trip valves. This trip is routed via the low forward power relay and is therefore time delayed. Motoring of the set under low vacuum conditions would cause rapid overheating of the turbine blades. This situation could arise if the low forward power relay interlock fails to close. A direct electrical trip from the low vacuum to the generator circuitbreaker is therefore provided: this has to be done electrically since operation of the power fluid pressure
switches is a delayed trip. The following explains how the electrical trip for low vacuum on a modern 660 MW turbine-generator is achieved. Turbine tripping is effected electrically by pressure switches which monitor the vacuum of the three 882
D.C. MOTOR DRIVEN LUBRICATING OIL PUMP
condensers. The two vacuum lines are brought out downstream of an arrangement of a ball shuttle valve, which automatically selects the condenser with the poorest vacuum and connects it to each of the two vacuum lines. The three condensers are interconnected by balance pipes, and hence trip initiation occurs if
the vacuum in any condenser falls below the trip setting. Four pressure switches are provided, arranged in a 'two from two' logic configuration per trip channel. 5.4 Condensate conductivity high Turbine tripping is initiated by conductivity transmitters used to monitor condensate contamination at the outlet from the condensate polishing plant and from
the condensate extraction pumps discharge pipework. A set of four transmitters is provided corresponding to each location and these will operate in a 'two from two' logic configuration per tripping channel for each set of transmitters. Each transmitter can be checked on-load, in turn, by adjustment of its set point. 5.5 Manual trip lever The turbine manual trip lever mechanically forces both
of the trip linkages connected to the two emergency trip valves into the trip position. The trip latches become displaced and cause the associated emergency trip valves to operate.
Turbine protection
5 . 6 Overspeed trip There have been incidents resulting in turbine-generators reaching a dangerous overspeed and every effort h a s been made in formulating the protection to reduce his danger. Overspeed occurs when the steam passing t hrough the turbine exceeds that required to match t he load. The turbine speed is controlled by the govt rnor to a speed lets than the o \.erspeed trip setting. e I n the event of the speed governor and its control ystem failing to dose the governor valves, an overs speed trip device attached to the shaft of the turbine acts directly to trip the emergency trip valves, closing both the governor and main stop valves. However, none of these safety measures will be effective if for some reason the governor and main stop valves fail to close properly. This could be for the following reasons: (a) Damage to main steam valve spindle or seat, e.g., cracking, surface pick-up or galling (swelling due
to Corrosion), (b) Hydraulic contamination of the hydraulic control fluid on a massive scale. (c) Water carryover from the boiler causing distortion of the main steam valve ducts. On-load testing arrangements, routine monitoring of the fluid condition, the existence of a secondary method of valve closure and the fact that the emergency stop valves and governor valves are series connected, combine to make the probability of the steam valves not closing due to causes (a) and (b) not credible. On the other hand, water carryover causing distortion and preventing valve closure remains a possibility. Thus there is a danger of overspeed. This risk is minimised by a protection interlock which ensures that the power output from the machine is reduced to a low level before the generator circuit-breaker is opened. The method relies on the fact that an overspeed cannot occur provided that the output from the generator is absorbed by the grid. If the generator remains synchronised until such time as the steam flow to the turbine has reached a safe level, then the danger of excessive overspeed is removed. In fact, the same argument could be used for the majority of the mechanical protection systems on the turbine. Loss of lubricating oil pressure is no more likely to cause water carryover or valve distortion than, say, a trip from a relay detecting an overcurrent condition. The decision was made that all protection systems which could tolerate a few seconds delay (until the turbine input power reached a low level), would be routed through an interlock which measures the power delivered to the turbine and prevents the opening of the generator circuit-breaker if this power is too high. A scheme was developed incorporating this interlock which categorised the various boiler/turbine-generator protective systems as follows:
Category A Those protecting against fault conditions which cannot tolerate a trip delayed until a low power condition is reached. Category B Those protecting against fault conditions which could tolerate a trip delayed until a low power condition is reached. For faults in Category A, avoidance of overspeeding rests solely with the steam/governor valves closing correctly, whereas those in Category B have the low power interlock effectively preventing the protection from opening the generator circuit-breaker, thus retaining the turbine-generator in synchronism until the steam supply is reduced to such a level where overspeed cannot occur. Except for two — loss of excitation and generator transformer winding temperature — all of the electrical protection systems to be described in Sections 6 to 9 of this chapter were selected for Category A because of the danger from high fault currents if these were allowed to persist for the length of time it could take to reach a low power level. For these faults the turbine hydraulic fluid system has to work correctly. Generator transformer winding temperature and generator loss of excitation trips were considered as the two protection systems that could wait for a low power condition.
5.6.1 Choice of interlock The interlock could be based on an accurate measurement of steam flow or differential pressure across the turbine but this is difficult to perform and investigations by the CEGB into these and other methods of measurement have not proved rewarding. It was decided therefore, that low power to the turbine could be measured by the electrical power output from the generator, using a sensitive low forward power relay. The contacts of this relay are in series with the Category B trip relay contact. The unit can only be tripped from Category B protection systems when the contacts on the low forward power relay close to indicate a power condition less than 0.7% from the generator to the system.
5.6.2 Setting of the low forward power relay A figure of 0.7% forward power was chosen as the setting point since, from curves prepared by the CEGB (Fig 11.12), it can be seen that the maximum allowable overspeed of 25% (guaranteed tested figure) is produced when the steam input exceeds the total machine losses by 0.7% at synchronous speed, and this sets the upper limit of operation of the relay. A low forward power relay was chosen as its contacts are dosed while the generator is being run-up and synchronised, thus permitting the protection to be in service. Further, a small steam leak occurring when the steam 883
7"' Protection
Chapter ii
LOSSES AS A % OF FULL LOAD
OVERSPEED FOR 0.7% FULL LOAD RELAY SETTING
1
0
1 CS
1.1
1.2
4.3 SPEED RATIO,
1.4 p.0
1.5
16
1.7
1 8
SPEED 3000 omm
FIG. 11.12 Low forward power rekay setting point for 60, 100 and 660 MW units
valve has nominally closed could be sufficient to cancel the motoring power, leaving the machine to float or run generating at low power, which is why a reverse power relay would not operate and is not suitable. The operating limits chosen are 0.2% to 0.7% forward power. Sensitive low forward power relays, such as the Brown-Boveri type PPX 110/111, have been specifically designed and approved for this purpose. Power measurement is by three-phase power measurement at rated voltage. The principle of operation- is explained with the aid of a block diagram (Fig 11.13). The voltage and current transformers of the generator are connected to the interposing transformers A or B, respectively. These transform the input values to the necessary level for the relay electronics. The current signal is converted into a squared voltage signal and during the negative half-cycles it is switched to the low pass filter by means of the field-effect transistor switch. This determines the linear average value and generates a DC voltage proportional to the active power. The phase correction network serves to compensate the phase angle errors of the measurement transformers. For three-phase connection the changeover switch on the summing amplifier must be set in position 3WM, and for two-phase connection (2 wattmeter method) in position 2WM. The summing amplifier adds the voltages proportional to the phase loads. The voltage at its output, 884
proportional to the three-phase power, is fed to the trigger which has an adjustable setting. Load selection is by means of the max/min switch located immediately after the trigger device. Blocking gates are provided to inhibit relay operation if: • The power supply is too low. • The relay is blocked externally. For relay type PPX110 the operating signal passes via the timing element and, if required, via bridging link (2) to an auxiliary relay. A second parallel route for the signal is via an inverter to the output terminal. On the type PPX110 relay, tripping can be delayed by 0.5-5 s and indicated by an LED; the setting normally chosen is 2 s. The auxiliary relay can be applied to supervise the 15 V stabilised power supply by closing the bridging link (3). Two timing elements are supplied with the type PPX1 11 relay, one delays the operating signal by 0.55 s and the other by 5-50 s. The following protective devices operate through the low forward power relay: • All turbine trips, except the low vacuum electrical trip of the trip valves.
INTERPOSIWG TRANSFORMERS
CHANGE OVER SWITCH
A
PHASE CORRECTION NETWORK
SQUARE WAVE CONVERTER
3WM
2WM
FIELD-EFFECT TRANSISTOR SWITCH
8 SQUARE WAVE CONVERTER
LED
AUXILIARY RELAY & CONTACTS
TIMING ELEMENT 05 -50s
2 Hz FITTED TO RELAY — TYPE PPX1 I ONLY
SIGNAL AMPLIFIERS TIMING ELEMENT 0.5 • 5s
—)^
AUXILIARY RELAY 3, CONTACTS
LOAD SELECTOR FIELD-EFFECT TRANSISTOR SWITCH
RESET
SUMMING AMPLIFIER
LOW PASS FILTER ■01.-
2 Hz
INVERTER
2 BLOCKING GATES
STABILISER AND VOLTAGE SUPERVISION
PHASE CORRECTION —0-NETWORK
SQUARE WAVE CONVERTER
RESET
LOW PASS FILTER
4
PHASE CORRECTION NETWORK
3
1 5V
141."
A
LINKS
FIELD-EFFECT TRANSISTOR SWITCH
LOW PASS FILTER
2 Hz r.■■■=.1
.111
INTERNAL/ExTERNAL TESTING
FIG.
11.13 Three-phase power relay — block diagram
uop3loid auqJni
CONNECTIONS TO MAIN GENERATOR VOLTAGE AND CURRENT TRANSFORMERS
BRIDGING
Protection • All generator mechanical trips, plus the generator electrical trips, which are described in Section 6 of this chapter.
5.7 LP exhaust steam temperature high If the vacuum is low and the spraywater system is being used to keep the turbine blades cool, a measurement of exhaust steam temperature is an indication of the failure of the spraywater system. This is not always a unit trip and depends on the turbine manufacturer. The spraywater system has its own protection; if it fails, the turbine is tripped and this will trip the unit through low hydraulic fluid pressure.
5.8 Loss of electric governor The latest turbines are fitted with electronic governors employing a redundancy system of electrical control channels in order to provide adequate security. As a final protection, in the event of failure of a sufficiently large number of channels to invalidate the redundancy system, or of any other failure which renders the governor inoperative, a signal will be given to trip the unit via the low forward power interlock relay.
5.9 Low steam inlet temperature and pressure Consideration of an incident in 1960, where a turbine oversped out of control, suggested that a loss of firing occurred and the feedwater regulation system was unable to cope with the transient. The result was water carryover that caused the turbine to overspeed. In that combination of circumstances, it was reasonable to contend that the major fault was a loss of firing and that the best available indication of this condition was low steam inlet pressure at the turbine. An unloading system had been evolved in 1954 for application to 60 MW and higher rated turbine-generators. The principle was to commence deloading at 90 07o of normal operating pressure and to reduce the load to 10 07o MCR by the time pressure had fallen to 85% of normal. Hence the unloading gear offered reasonable protection against water carryover, since the most probable cause of carryover was the combination of feedwater regulation or partial firing. Later, in 1969, a form of tripping from low steam inlet pressure was recommended. However, due to the low reliability of the system, which caused a number of spurious trips, the equipment was taken out of service in the mid-1970s. The principle of low steam inlet pressure protection, whilst being acceptable when the grid was supported by a large number of small units which operated at fixed pressure in the 70% to 100% MCR range, was not suitable for newer modes of operation, which included sliding pressure operation. To continue with its application therefore required an updating of the design, 886
Chapter 11 refurbishment of the hardware and the application of sophisticated veto facilities. This was considered i n . appropriate and expensive and therefore the discon_ tinuation of the application of low steam pressure deloading and trip equipment on high pressure fossi1. fired plant was recommended on all 500 MW and 660 MW units, the main grid supporting stations. This change in protection philosophy left the turbine at risk to water carryover in the event of a total los s of boiler firing. It is now standard practice on all the 660 MW units at conventional power stations to design on the basis of the operators taking corrective action, which must be done within I minute. To facilitate this, the following features are provided: • A suitable alarm is initiated from a total loss of firing. • The status of the flames in the furnace is displayed. • The pertinent steam pressures and temperatures are displayed. • An emergency trip pushbutton is provided. All the above facilities are mounted on the appropriate unit control panel/desk within a single viewing angle. Nuclear power stations, with once-through boilers, have a short time constant for the passage of steam from the boiler to turbine, and there is insufficient ti me for the operator to be sure of preventing water carryover to the turbine for abnormal boiler conditions, as in conventional stations. There was therefore no alternative but to provide an automatic trip by the inferred measurement of steam saturation from readings of steam temperature and pressure.
6 Generator protection The protection arrangements for the generator necessarily include the main connections and transformer windings connected at the generator terminal voltage. The generator transformer protection arrangements will overlap with generator protection, especially where the generator is directly connected to its transformer. The generator protective systems are listed on Fig 11.35.
6.1 Stator earth faults (low impedance earthing) Prior to 1950, established practice was to earth the generator star point using a voltage transformer, the secondary of which generally operated an alarm. Following a number of serious breakdowns in the gen erator windings during 1950 and 1951, this practice was discontinued and replaced by low resistance earthing using a liquid earthing resistor. The aim was to li mit the fault current to 300 A for all sizes of gen , erators. The time rating of the resistor was 30 seconds although 10 seconds was allowed if difficulty in ae-
Generator protection ,.orurnodation made this necessary. This policy was wed for all machines including 500 NAW. -. 0 1lo I The ear th fault protection using this method of e, consisted of two series-connected relays (Fig jrt hi n e pplied from a single 300 A current transformer i 04 ) su uenerator neutral connection. The first of these •h the tavs is an instantaneous type and the second has re , mverse time characteristic. Jr The factors affecting the choice of the relay charies and settings are described in the following :ter i st aragraPhs. The zero sequence voltage for a fault on the transmission system is in the region of 50 to 60 kV and h e maximum surge voltage is limited to approximately 1100 kV by the setting of the co-ordinating gaps. In the normal way, earth fault protection on the generator should not detect these voltages as the LV k inding is delta connected. However, the interwinding ■ and winding to earth capacitances form a potential divider with the generator neutral earthing system and small part of the zero sequence voltage and the surge a oltage will appear on the LV side. With a relay setting 07 5 0 of the nominal earth fault current, chosen to protect as much of the winding as possible without the clanger of malfunction from standing capacitance currents on the LV side, there is a danger that operation irom zero sequence voltages could occur if the relay was instantaneous. At this level of earth fault current (15 A), it was necessary for the protection to be time-delayed to !,/rade with the protection on the HV side of the generator transformer. The 10% setting (30 A) was above the calculated transmitted voltages appearing across the earthing system and therefore was made instantaneous. So two relays were provided, one set at 5% %kith an inverse time characteristic and one set at 10% with an instantaneous operating time. Core burning with levels of earth fault current up io 300 A is inevitable, despite instantaneous tripping, , a an alternative form of earthing consisting of high
resistance, which limited the maximum earth fault current with nominal terminal voltage at each earthing point to 10 A, was subsequently introduced.
6.2 Stator earth faults (high resistance earthing) Following a desire to keep the core burning effects of earth faults to a minimum, methods of earthing through a higher impedance have been introduced. The CEGB initially assessed two systems of earthing which limited the fault current to 2-3 A and 10-15 A respectively. The factors under consideration were that whilst the resistance in the generator neutral requires to be as high as possible, it must not be so high as to give rise to excessive overvoltages caused by neutral displacement. The displacement of the neutral in relation to the voltage of the line terminals due to abnormal system conditions, other than short-circuits, is known as neutral inversion. Consider a set of impedances star connected to the neutral N, Fig 11.15 (a). Then, if the sum of the phase voltages to N is zero, N is defined as the geometric centre. In the general case, where the neutral N is not directly earthed, if an unbalance of the phase to neutral impedances occurs, then a voltage will appear between neutral and true earth. Considering Fig 11.15 (b); let P be at the geometric centre, i.e., the voltages to it E a , Eb, E c , sum to zero. Let the star admittances to the neutral point N be Y a , Yb and Y e . Then if N is an isolated neutral, the sum of the currents entering N is zero. Let D be the voltage between P and N ia = ( Ea — D) Ya Ib = (Eb — D) Yb = (E c — D) Ye
Since 1 a +
lb
+ I = 0 then
E a Y a + Eb Yb + EY e = D (Y, + Yb + Y e ) (11.1) MAIN GENERATOR
From this, if Y a = Yb = Ye, (Ea + Eb E c ) = 3D and, since E a Eb E, = 0, then D = 0, N coincides with P and, if P is an earth point, then N is also at earthed potential. Now if the 'a' phase is open-circuit so that its admittance to N is zero, (X a = co and Y a = 0) and if E a and, Yb = Ye, then from Equation (11.1) D = on a balanced system of voltages, N has moved to N' (Fig 11.15 (b)). Thus the voltage between N and earth a. If the three-phase system becomes unbalanced, with the 'a' phase purely capacitative and 'b'/'c' phases capacitative and inductive then Ya = icoC, Yb
FIG.
11.14 Low resistance
earthing
i/j(coL — UoiC) = — jc4C/(w 2 LC— 1).
Then, from Equation (11.1) D = E a (w 2 LC)/(co 2 LC -3) 2 and N moves along AB depending on the value of (..., LC 887
Protection
Chapter 11
J
O
PCSIT•ON OF - 4' iF a PHASE IS OPEN
f
_
3 3.
a
n,
".erS or
qrf
VOLTAGES
GROUNO
EARTH FAULT CURRENT PHASE
a:
I
1.
• •
!i‘
Cl 0,e,cnrages due TO auli cufrert eessatqn 01 system frequency zeros Cr. a sysf ern +de, be neutral nsulafed.
400
RANSNF VLXTAGES NOHMAL CHES I TO EAH TH
)60 -1
020
-
240 200 NEUTRAL TO EARTH 60 -
'20
00 R 3 40 -
02
0.4
00
00 KW
I C
1 2
1 4
I6
1 8
20
DISSIPATION OF R
° CAPACITATiVE 30 CHARGE 10JA •of Damping effect of ftJER on generator avervollageq
FIG. 11.15 Overvoltages on high resistance neutral due to neutral inversion and arcing ground faults
888
and the voltage between P and N can be very large if bi 2 LC approaches 3 in magnitude, i.e., series resonance occurs and N moves to infinity. As far as the generator and its earthing system i s concerned, the latter condition is unlikely but it does demonstrate that excessive overvoltages can occur if the phase to neutral impedances become unbalanced when the neutral is not grounded. Excessive overvoltages can also be caused by arcin g ground faults on an unearthed generator system resulting from cyclically recurrent earth faults in the manne r described below. When the earth first occurs, the net'. tral will oscillate sinusoidally at system frequency. I n the worst case, if the arc is extinguished when the neutral is at phase to neutral voltage, the trapped charge in the system capacitance will hold the neutral at this peak voltage so that the faulted phase voltage will n ow oscillate from ground potential to twice the phase to neutral voltage. Should the arc restrike when the phase voltage is at a maximum then it is brought down to ground potential and the voltage on the neutral becomes phase to neutral voltage. The neutral then oscillates sinusoidally at system frequency as before. This condition is reached through an oscillation whose magnitude is controlled by the circuit damping and an oscillation frequency based on the natural frequency of the system. This is shown in Fig 11.15 (c). Work carried out in the USA shows that the critical damping which will reduce these excessive overvoltages to a minimum is when the value of the earthing resistor R = 1/3 the per phase generator capacitance to ground (Fig 11.15 (d)). The value of R for critical damping on the CEGB generator voltage system is such as to limit the current to 2 to 3 A. However, experience has shown that resistance earthing of the neutral point which restricts the earth fault current to not less than 5 A, provides an effective earth anchor under all operating conditions and avoids the two conditions described. A practical resistance, designed for direct connection to meet these criteria, would be both unwieldy and costly, since the resistance would have to be about 1300 and the design such as to ensure against mechanical failure. Use is therefore made of a matching transformer with a suitable turns ratio, chosen to permit a robust heavy current low-valued resistor to be connected to the low voltage winding having a value, when viewed from the high voltage side, equal to that required for direct connection. The choice of such high values and the use of a transformer introduces certain other technical problems, apart from those arising from overvoltages mentioned previously, and the choice of transformer and relay connections is influenced by other considerations. These are as follows: • The working flux density of the transformer has to be chosen to ensure that under maximum voltage
Generator protection
1 across the primary (maximum field-forcof the generator on open-circuit), the core iron ina below its knee point. This is to prevent the ossibility of ferro-resonance with the generator P ,3paCitanCeS causing overvoltages on the generator tem under fault conditions. Ferro-resonance is a i t i o n where the transformer exciting impedance .r orms a resonant circuit with the supply system p3citance. he resonant frequency is usually sub1 norma l. If the neutral is displaced as described rroiously, it could drive the transformer into sattiration, the transformer could then resonate with he system capacitance. If the frequency passes ugh a third sub-harmonic, the oscillation could, ro absorbing energy from the system, be maintained b% indefinitely. Allowing for an open-circuit overvoltage f the generator of 140%, the flux density at this o oitage is arranged to be between one-half and twothirds of of that at the knee point. • The X: R ratio due to leakage reactance of the transformer and the combined resistance of the transformer winding and earthing resistor should be less than 2. This requirement keeps the power factor of an arcing ground fault as high as is practical in the interests of keeping restriking transients down. • The impedance to earth of the neutral point of the generator should not be so high as to allow the effects of voltage unbalance produced on the HV ,ide of the generator transformer by system earth faults, to transmit voltages on to the neutral earthing resistor via the transformer interwinding capacitance and thereby to cause unwanted operation of the ,tator earth fault protection.• ,
• With the relay setting sensitivity being such as to detect 0.5 A (5% of 10 A) in the generator neutral, the effect of harmonic generated voltage, acting through the machine capacitance to earth and the neutral resistor in series, has to be taken into consideration in the relay design. Both earth fault relays are tuned to 50 Hz to eliminate these third harmonic currents. To avoid the problems introduced by designing for low neutral currents, it is present practice to design for neutral currents of 10-15 A. This has been done on all 660 MW sets. The practice of designing for 2-3 A used in the past, led to problems in locating earth faults which caused the operation of protection circuits. A description of the design of the matching transformer and the current limiting resistance is given in Chapter 3. The earth fault protection using resistance earthing through a distribution transformer is shown in Fig 11.16. Two methods of protection are used. One (relay RI) is CT operated and the other (relay R2) VT operated. In both methods of protection, the relay used is the same and comprises an induction disc with an adjustable inverse time/voltage characteristic (Fig 11.17). The coil circuit is tuned for system frequency by a series-connected reactor and capacitor. These components are energised from a tapped auto-transformer which provides the adjustment of the relay voltage. At voltages above the setting, the reactor saturates and detunes the circuit, giving the relay a high continuous voltage rating. Tuned wound shading coils are fitted so that the relay develops maximum torque at the system frequency
MAIN GENERATOR
RELAY R3
RELAY R2
INTERPOSING VOLTAGE TRANSFORMER
FIG.
11.16 Generator neutral earthing by distribution transformer
889
• ▪
Protection
Chapter 11 TRIP CDT SUPPLY TRIP
ALARM 3
41
8
10 ("N
•
T, = current transformer turns ratio current transformer magnetising current IC [sr = relay current at setting V, = relay setting voltage relay impedance at setting Zr Required fault setting = (IfT y )(5/100) relay circuit current I = Ii (0.05 x T)/T s T, (I, + I sr + Vr/Zr) = Et (0.05 )( Tj The knee point voltage V k must be greater than that required to drive current through the secondary circuit impedance for maximum earth fault conditions, therefore Vk must not be less than 1.4 liT v /T,(R., R„ + R)V
AUX UNIT
SHADING COILS DISC UNIT
FIG. 11.17
Earth fault protection relay
and is much less sensitive to third harmonic frequency. A setting range of 5.4-20 V is provided (the third harmonic setting is at least 20 times higher). Where the relay is CT-operated, a setting resistor is used in parallel with the relay as shown in Fig 11.16. Where the relay is directly measuring the voltage across the earthing resistor (also shown. in Fig 11.16), an interposing voltage transformer is used to limit the maximum voltage across the relay under the worst fault conditions to less than its continuous voltage, and to enable a setting of the protection to be 5% of the maximum earth fault current on open-circuit and nominal generator terminal volts. In order to help clarify the protective arrangement the following shows 507 earth fault the process adopted to arrive at this setting of each protective system. Many CEGB power stations have the earthing system designed for a continuous rating. This is because the stator earth fault protection was routed through the low forward power relay interlock and therefore could be maintained for the operator to clear the low forward power condition. However, in light of experience where an earth fault developed into a phase-to-phase fault before the protection tripped the HV circuit-breaker, the stator earth fault protection is now a direct trip. The matching transformer was therefore made much larger than it needed to be. 6.2.1 Current transformer requirements for protection using relay RI
Let 11-
= earth fault current at nominal voltage T v = matching transformer turns ratio
890
where Rct = resistance of the current transformer R, = resistance of the wiring to the relay Rr resistance of the relay R, = resistance of the setting resistor R, R,11,/(R r + Rs) The rated primary current A1 (not turns ratio) must be equal to 1.4T y Tr . The calculation becomes very involved unless some values are now given to the CT ratio and the setting voltage on the relay. From experience, the CT ratio is chosen as 300/1 and the voltage setting on the relay 5.4 V (minimum). The maximum voltage across the relay is specified not to exceed 120 V. The other consideration is to maintain the voltage characteristic of the relay, i.e., the voltage across the relay proportional to fault current. So the resistor current needs to be large compared with the magnetising current of the CT at the maximum fault current. The matching transformer ratio is 66 : 1 (33 kV/0.5 kV) so, with a nominal 10 A earthing current, the setting current is 33 A (Sri) x 660). With the minimum voltage setting on the relay of 5.4 V, the setting resistor value R, = 5.4 (300/33) = 49 O. The maximum continuous fault current through the setting resistor, assuming a maximum open-circuit voltage from the generator of 1.5 times nominal voltage and a fault just less than 5% from the generator neutral, will be (1.5 x 33/300) A, so the continuous rating 2 of R, has to be not less than (1.5 x 33/300) x 49 = 1.33 W. 6.2.2 Matching transformer
The short time rating is 15 A for 3 s, based on a 1 s operating time of the protection at the maximum fault (15 A) and 45 A for 1 s for a short-circuit of the loading resistor. The continuous rating is 0.5 A, based on a fault current just below the protection setting. Where a generator voltage circuit-breaker is used the same arrangement is used on the neutral connection of the earthing transformer (Fig 11.18). The earthing transformer provides an earth for the connections and transformers windings at the generator voltage when
Generator protection
GENERATOR SYSTEM
EARTHING TRANSFORMER
RELAY R2
FIG. 11.18
Neutral earthing of a generator system with a generator voltage circuit-breaker
he Lrenerator voltage circuit-breaker is open. This proection is time delayed to grade with the generator ,[aLor earth fault protection which trips only the :! enerator voltage circuit-breaker. If the fault current .. ontinues to flow in the earthing transformer neutral, ;his protection trips the HV circuit-breaker and the unit transformer LV circuit-breakers to isolate the resulting in a loss of supply to the unit auxiliaries. If the fault current ceases to flow in the earthing [ransformer neutral, indicating a generator stator earth Cdult, then the supplies to the unit auxiliaries are main:dined. This is very important at nuclear power stations here it is essential to maintain grid supplies to the . : ential auxiliaries without the need to run auxiliary In order to keep costs down, however, the generator ohage circuit-breaker used on earlier nuclear stations as replaced by a generator voltage switch disconAeL:tor, so that grading could not then be obtained and both generator earth fault systems tripped the . generator by opening the HV circuit-breaker without iiine delay. If the primary or secondary of the matching translorrner becomes short-circuited, the earth fault pro-
!ection of. the generator is lost. The fault would then be detected by stator differential protection (see Section 6.3 of this chapter) if provided. The overall protection 31 the generator and its step-up transformer is insensi!ke to earth faults, so that at conventional stations ', there stator differential is not provided, an earth fault ould go undetected. Even at nuclear power stations itilising isolation at generator voltage, approximately 10 N of the winding would be unprotected, the actual amount depending on the setting of the stator differ-
ential protection. In order to limit the possibility of an earth fault on the neutral connection, which effectively shorts out the earth fault protection, the earthing transformer is mounted very close to the generator neutral connection and additional protection is provided from a current transformer mounted in the generator neutral connection operating into an instantaneous relay (R3 on Fig 11.16). The protection is set to detect fault currents in excess of 25 A. The earthing transformer system for earthing on the generator transformer side of the generator voltage circuit-breaker (required only when a generator voltage circuit-breaker or switch disconnector is used) has the matching transformer under oil in the same tank, so reducing the possibility of short-circuiting the protection and thus the additional protection of an instantaneous relay in the neutral is not provided.
6.3 Stator phase to phase faults Phase to phase faults clear of earth are less common than phase to earth, but earth faults can develop into phase to phase faults. They may occur on the end portion of the stator coils or in the slots, if the winding involves two coil sides of different phases in the same slot. If the latter, the fault will involve earth in a very short time and will be cleared by the earth fault protection but only after a time delay, due to the inverse character of the relay. Fast protection against phase to phase faults is achieved using the circulating current principle, with either a differential protection system, using biased relays, or a differential system of protection using high impedance relays. The method adopted depends upon the plant included in 891
Protection the protection zone, a biased relay if across the generator and generator transformer, or a high impedance relay circuit if across the generator only. Before explaining the CEGB philosophy on the choice of zones of protection, an explanation is required of the principles of these two protective schemes. Both protective systems employ current transformers on both sides of the protected plant. The CT ratios are chosen such that the current flows only in the secondary windings of the current transformers and not in the ;day operating coil circuits under load or through fault conditions. Under internal fault conditions, the secondary equivalent of the fault current flows in the relay operating circuits. However, when the generator and generator transformer are included in the protected zone, the following complications are introduced: • On energisation, the magnetising current surge produces an out of balance current in the relay operating coils. • All generator transformers are equipped with tapchangers, and the transformation ratio can only be matched at one tap position. Thus, at other tap positions, out of balance currents flow in the relay operating coils making it difficult to obtain a low setting. • Differences in the design characteristics of the CTs
on the high and low voltage sides are often unavoidable. The effect of magnetising inrush current is eliminated by means of a harmonic bias unit which selects the second harmonic component of this current and uses it to restrain the relay during the surge period. The out of balance currents caused by off-nominal tap positions and the differences in CT design characteristics are overcome by the use of bias windings in the relay. Figure 11.19 shows a typical magnetising current surge. The waveform indicates a predominance of second harmonic. Figure 11.20 shows a relay using a transductor (Reyrolle 4C21). The harmonic bias unit is a si mple tuned circuit which responds to the second harmonic component of the magnetising current. The rectified output of BR2 is injected into the transductor input biased winding and restrains the relay.
110". 1 1-4— CYCLE
—
1
-4— INSTANT OF SWITCHING
Fto. 11.19 Typical transformer magnetising current waveform.
892
Chapt er 11 The out of balance currents and current transformer mismatch currents are not large enough to overcome the DC bias iVI MF (Fig 11.21), so that the flux chang e is small. For internal faults, the operating MMF pro. duced by the much greater current involved (about 20 ti mes) exceeds the bias IvIMF, resulting in a large change in working flux in the output coil to the relay. H ence the minimum operating current of the relay depends on the bias current. This produces a characteristic for the relay as shown in Fig 11.22. It can be seen that, for faults near to the neutral of the transformer which have only a small effect on the bias current, the rela y is very insensitive. Further, the higher the bias setting the more insensitive the relay becomes. The current transformer ratios are therefore chosen to match the middle of the tapping range rather than the nominal tap, which is nearer to one end of the winding. For example, with a ± IO% tapping range, the relay is set to cover a deviation of 10 07o. A factor of 2 is applied to ensure stability under through-fault conditions, i.e., 20% bias. The operating current setting, i.e., no bias current, is fixed at 20 010. This gives an actual setting of 50 07o with full-load bids current. Note that halving the operating current Setting to lin reduces the actual setting with full-load bi,is current to only 40 07o, so that a setting lower than 20' 10 is not chosen. The setting leaves the bottom end of the winding unprotected, so that additional earth fault protection is provided to cover this part of the winding. This is also necessary for faults higher up the winding if the neutral of the transformer is earthed through an earthing resistor which restricts the earth fault current to less than full-load current. A further consideration in earth fault sensitivity is that the majority of power station power transformers are star/delta connected or star/star with one star point unearthed. Typical connections are shown in Fig 11.23. If the star point of the biased differential relay is connected to the star point of the interposing current transformer, there is a mismatch of the zero sequence currents under through earth fault conditions. The relay acts as a shunt path to the tertiary winding of the interposing CT. It is CEGB practice, therefore, to eliminate the zero sequence currents from the relay circuit by leaving the star point of the relay operating coils unearthed. Figure 11.24 shows the arrangements for the generator and the unit transformer when the generator has a means of disconnection at generator voltage. The CT knee point requirements for restricted earth fault protection and biased differential are the same, so the two protection systems are combined on the same set of current transformers. The earth fault protection is designed on the same basis as all differential protection, using a high im pedance relay circuit. The basic principle of the protection is that it should be stable for the heaviest through fault and that the worst condition for this Is
Generator protection
CT
GENERATOR TRANSFORMER
CURRENT TRANSFORMER
d
y—y—yvr BIAS WINDING •—
'"
O
E7F-1 TRANSDUCTOR INPUT BIAS
WINDING
INPUT OPERATING WINDING
RELAY ELEMENT
OUTPUT WINDING TO RELAY OPERATING COIL
TRANSDUCTOR
BR2
HARMONIC BIAS UNIT
FIG. 11.20 Transformer biased differential relay
:( one CT of a balancing pair saturates and the other one does not. This gives the maximum voltage appearng across the relay circuit. The principles adopted are as follows: 'd} The relay circuit is of such high impedance that it can be set above the maximum voltage that can occur for through fault currents for which the protection should be stable. 1
h) The knee point voltage of the CTs must be twice the setting voltage.
In considering (a), the worst case is where one CT in a 'oalancing circuit saturates. It is assumed that this CT 'hen produces no output and presents its resistive burde n only. Referring to Fig 11.25, Vs must be -.-reater than IFS (RA ± Rc) or IFS (RB + RD),
where 1Fs = maximum secondary through fault current Vs = relay setting voltage. This is the simple case and is the basis of the calculation when applying high impedance differential protection to the generator. The generator transformer protection is more complicated when biased differential protection and earth fault protection are combined on the same current transformer and reference now is again made to Fig 11.23. The complications are that apart from the resistances of the primary circuit containing the restricted earth fault relay, there are also the reflected impedances of the overall differential relay circuit. If we consider first of all the earth fault at X in red phase Fig 11.23, the secondary earth fault current in the primary of the interposing CTs will produce 893
Protection
Chapter 11
—
ETSING
GURVE
TRANSFORWIR M,AACIN X u-
AC OPERATING CURRENT
DC BIAS MMF
FIG. 11.21
Biased differential relay operation
The fault setting is (fs + 31 1 + I2)/Ti BIAS SETTING
.1 0%
30%
FIG.
11.22 Biased differential relay operating characteristics
currents in red and yellow of the overall biased differential relay, as shown. Now assuming the voltage across the operating coils (R 0 ) of the biased differential relay is zero, the resistance of the loop is (A + B + F + G) + (H + 2K + ROIT2/T31 2 = R, where the second term is the resistance of the circuit across the secondary of the interposing transformers referred to the primary winding. V s must be > IF/T1 x R. for the line CT saturated or > 1E/T1 x N for the neutral CT saturated whichever is the greater. 894
where Is = relay current at Vs volts Ii = magnetising current of line CT at Vs volts 12 magnetising current of CT in the transformer neutral In order to achieve a low setting on a transformer with a tapchanger, biased differential protection with a low impedance operating coil is required. If the protective zone contains the generator only, then the differential protection using a high impedance operating coil circuit is required giving a lower setting for the protection, fast operating times and a high degree of stability. There is therefore a case for two protection zones, one across the generator and one across the transformer, since one zone covering both must always be a compromise. Where a generator is directly connected to the LV side of the generator transformer, as has been the practice for all fossil-fired power stations to date, any fault inside the zone must open the high voltage circuitbreaker. The protection of the stator against phase faults is therefore included in the generator transformer biased differential protection using a biased relay, and a separate zone of protection for stator winding phase faults is not provided, i.e., one zone only. Nothing would be gained from an operational point of view by detecting whether the fault is in the generator or in the transformer. Further, all protection CTs can be mounted on the generator neutral connections, which from a practical point of view is an advantage. Refer" ence to Fig 11.26 shows the arrangement.
Generator protection
GENERA ToR N IRA NA 12 III
C 7s
I R LA RCul
-
.NITRPOSING 7.ANSFORMEP
BIASED IDIFFERE'V - IAL RELAY
TURNS NATO "7.4= _NE AND CURRENT TRANS' s. `IERS OPERATING COILS
_ 7 1- P4S RA PO N7ER PCS'. 13 - CURRENT TP.AN5FOP.,1E=3 ,
FIG. 11.23 Overall biased differential protection circuit
Without the fast differential protection on the gen...rator and connections, additional protection is rered to provide fast clearance of generator faults, or :auks on the connections to the transformers. Winding ILilts start as earth faults and are generally cleared by ...,11(h fault protection. The CEGB provides additional .ht phase-fault protection by means of a high set n,tantaneous relay on the HV side of the generator . p- u p transformer. Protection using art instantaneous is more fully explained under HV and LV connecHoly, protection, but the principle is to obtain a setting 'or an instantaneous relay which is stable for system 1400 kV) faults but is sensitive enough to detect genrator faults. Where a generator voltage circuit-breaker is pro:Li d at the generator voltage level, as at some nuclear ' ions and at Dinorwig pumped-storage station, a id.L.It on the generator detected by the protection as .ksing on the generator can be cleared by opening that nerator voltage circuit-breaker, thus maintaining escntial supplies to the unit auxiliaries via the generator r.Insforme r and unit transformer. Furthermore, acornmodation for the current transformers can be pro.Jed in the generator voltage circuit-breaker. A two /one differential protection scheme is therefore used. Back-up protection for stator winding phase faults Provided by means of a directional overcurrent relay. .
.
-
.
. ,
A typical directional relay consists of a voltage polarising unit and an ordinary overcurrent unit. The directional element relay (Fig 11.27) operates on the induction wattmeter principle and consists essentially of an aluminium sector mounted on a vertical spindle and arranged to rotate in the airgap between magnetic fields derived from line current and voltage transformers. Under healthy system conditions, the torque produced on the relay restrains operation. On current reversal, here a fault on the generator, the torque reverses and causes the moving sector to close contacts in the shading coil of the inverse time overcurrent unit. This allows settings lower than normal generator load currents to be set on the relay and restricts operation to faults on the generator permitting fast back-up protection for generator phase to phase faults, which can be cleared by opening the generator voltage circuit-breaker. By positioning the CTs in the generator voltage circuit-breaker on the generator side, faults can be cleared from the system by opening the generator voltage circuit-breaker only. A direct (Category A) trip of the generator and turbine is also initiated. The protection used for the connections from the generator voltage circuit-breaker to the generator transformer is described in the Section 9 of this chapter, on the protection of HV and LV connections. 895
Protection
Chapter 11
DiEFERENDAL PROTECT:0N
(
MAN GENERA TOR
EAP NG RANSFORMER
BIASED DIFFERENTIAL PROTECTION
UNIT TRANSFORMER
Flo. 11.24 Overall unit differential protection scheme with generator voltage switch
X
SET 1
SET 2 (ThrY^Y")
RA
r-Y"‘
R, r-NrYle")
R,
1--
111■•■
R,
RELAY RELAY RELAY CIRCUIT CIRCUIT CIRCUIT
.
-
7 77
FIG, 11.25 Generator phase and earth fault protection
896
Generator protection
OAA:N GENERA TOR
GENERATOR TRANSPOPMEA
,
BIASED OIEEERENTIAL RRoI7ECTION
BIASED
DIFFERENTIAL pROTEC TION
FIG. 11,26 Overall unit differential protection scheme without generator voltage switch
the standard HV test (this applies particularly to the overhang portion of the winding). • Winding vibration/movement under fault and normal load cycling conditions, coupled with the associated loosening of electrical connections. IR P
ARSI
7
• Moisture, due to stator conductor cooling water leakage into the gas system.
LU
AO. SUPPLY
8
•■■•
CUP UNIT
UORTING CONTACTS
CURRENT COIL
• Complete or local loss of stator conductor cooling water during test or fault conditions.
T?"
_
• Contamination of the stator winding cooling circuit.
VOLTAGE POLARISING COIl CISC UNIT
XE SHADING COIL,
Flo. 11.27 Directional element relay for phase fault protection
6.4
• Moisture due to insufficient dry-out of the generator when placing it in initial service, or after a prolonged outage when the stator has been degassed for maintenance/repairs.
Stator turn to turn faults
Turn to turn winding faults may start from the following causes: • The use of faulty material or damage caused during manufacture, which may not have been detected by
The present protection arrangement relies on the interturn fault developing into a fault capable of being detected by one of the protective systems described. Evidence shows that it can take several seconds for an interturn fault to develop into either a phase to phase or phase to earth fault, by which time severe stator damage can occur. Protection which detected the shorted turn condition could avoid much of the damage by earlier tripping of the machine. Several systems for the detection of such faults have been, and are being, considered by the CEGB. One, called 'split phase protection', utilises the fact that each stator winding consists of two parallel windings and detects turn to turn faults by measuring any difference in the current in the two windings. This protection is not yet recommended as a trip function, due to the difficulty in arriving at a setting that is stable for 897
Protection
Chapter 1
system faults but sensitive enough to detect a turn to turn fault. At present, a prototype is in service but on 'alarm' only.
6.5 Negative phase sequence Negative phase sequence ('JPS) currents in the generator stator are caused by unbalanced loading or unbalanced faults. Unbalanced loading is usually caused by an open-circuit of one phase at some point in the
\11111. •
system external to the generator and may persist for sufficient time to cause dangerous overheating of the
generator rotor. With the increase in size of units, the allowable ti me for the negative phase sequence currents to flow in the generator without damage has diminished. For this reason, the negative phase sequence protection must trip the unit directly (Category A). This protection is duplicated, one relay connected into each tripping system. A sensitive negative phase sequence alarm with continuous remote indication is also provided to warn the operator of increase in NPS level in the generators.
6.6 Loss of generator excitation Failure of the excitation system results in the generator losing synchronism and operating as an induction generator, drawing its excitation from the system. Before proceeding further to describe the form of protection, a discussion on the mechanism of 'asynchronous' running and operation as an induction generator is required. There are several words associated with engineering which have a prefix a such as asymmetrical, astatic, etc., in which the a in front of the stem word can mean either `not' or 'other than'. 'Asynchronous' means 'other than synchronous' and, as applied to any rotating AC electrical machine, means non-synchronous operation. Asynchronous operation as applied to a turbine-generator, however, is confined to describing its operation out of synchronism but with the rotor winding unexcited. It is technically asynchronous when pole slipping, but the term 'pole slipping' is reserved in Britain for simple running out of synchronism with the rotor winding excited. Pole slipping causes severe voltage, power and reactive VA surges to take place on the system whereas asynchronous operation, although technically a pole slipping condition, is quite innocuous as far as the system is concerned. The effect on the transmission system is small but the voltage depressions on the power station auxiliary system can be large enough to cause voltage instability of the induction motor drives. To understand the mechanism of asynchronous running, a reference to the steady state performance chart (Fig 1 1.28), shows that under conditions of minimum excitation, the smallest current to support full load MW is 1.63 p.u. (typical of a machine where Xd = 2.0 p.u.). In this condition, the whole of the rotor 898
4
k,1 VI
ThEOREVCAL S7ABrL.
FIG
.
T
e
11.28 Basic performance diagram
flux is used in producing real power (MW) and th e rotor current is supplied from the stator by transformer action. If, for example, 94 000 ampere-turns are nor_ many needed to maintain full output (60 MW ge erator), then, if the field switch is open, the rotor s reduced to one effective turn, i.e., axially down one side and back up the other. The current required is then 94 000 A. Further, in order to produce the voltage required to drive this current through the rotor iron and end bells,the rotor has to be driven asynchronously at a speed above nominal, i.e., higher than 3000 r/min for a two pole machine, and it behaves as an induction generator. The currents flow in the surface of the rotor due to skin effect, concentrating in the outer centimetre or so. It can be seen therefore that as far as the rotor is concerned, the situation is eased if the turbine is tripped, since the power output drops from the loaded condition to that required to overcome the losses in the generator and turbine. The generator then behaves like an induction motor on light load. The current required reduces to a level that can be tolerated as a continuous operation as far as the machine is concerned. However, MVArs are still drawn from the system (rated MVA/Xd), resulting in an unacceptable drop in voltage to the auxiliary system if allowed to persist for any length of time. En the past, protection provided for this type of fault was arranged to operate an alarm only. However, with the increased outputs and higher specific electrical loadings of modern generators, the time available to run under loss of synchronism conditions is much reduced. This is primarily because of the aster rate of heating of the rotor surfaces, and consequently the increased risk of damage. Additionally, the generator and unit transformer voltage is considerably reduced under loss of synchronism conditions. Depending on system connection and loading condition, the voltagereduction could be sufficiently severe to cause opera tion of the undervoltage protective devices fitted to boiler auxiliaries. Hence, it has been decided to arrange
Generator protection
11 . or
automatic tripping of the unit in the event of loss
„02 i r ation• f generator excitation' protection is proo impedance measuring relay. The relay 1.) ,. a n he change in impedance of the generator t al load conditions to that of total or partial norm ,,itation and is time delayed to avoid tripping res:o crabIe transients. relay is basically a mho type relay and the circuit is shown in Fig 11.29. A voltage ...,:orctical injected into the voltage circuit from the transthe polarising and restraint fluxes are disor A by the tuning capacitor C. The auto-transformer , :J he voltage applied to the restraining coil by : 1,iint5 t racior K. Referring to the loss of excitation phasor diagram on Fig 11.30: ,
At balance, — Icos(0 — 0) = K(V + [Zn) sin o or — [cos(0 — 0)/Ksin r V + IZB giving, Z = V
Za
KsinO where Z is the impedance the relay is measuring. In the field failure relay, the polarising flux is made to be in phase with the applied voltage by tuning the polarising coils to unity power factor and the flux in the restraint coil to lag the voltage by 60 ° (0=60'). 2 Thus Z — cos (0 — 90) — V3K
ZB
= — K [cosq5 cos 90 + sin 0 sin 90] — Z5, where K1 = 2/./3K = — K1 sin — Z B
he operating torque of the relay « (Dpol ,lop sin [(90 + (0 — 0)]
and the relay characteristic plotted on an R-X diagram is shown in Fig 11.31. It is not intended that this protection should provide cover for all possible pole slipping conditions but it must not operate under recoverable system swing conditions. With the heating time constants involved, a unit trip can be routed through the low forward power interlock relay, although the CEGB now favours a direct trip. A typical tripping system is shown in Fig 11.32 and the operation is described as follows. Operation of the
« — (V + IZB) x Icos (4) —0) I.te restraint torque « 43pol (Dres sin 0 cc
—cos(6-0)
+K (V 4- IZB) 2 sin 0
ji,n L e the torque on the relay is « — (V + IZB) x Icos(5 — 0) — K(V + IZB) 2 sin cb
RELAY RELAY
MOVEMENT (I NDUCTION CUP)
OPERATING COIL \ CURRENT VOLTAGE TRANSACTOR
0
RESTRAINT COIL POLARISING COI LS
AUTOTRANSFORMER
r`trY"M. t TRANSACTOR VOLTAGE OUTPUT
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FIG. 11.29 Loss of generator excitation protection circuit
899
Chapt er .1
Protection
, • • po ANC) (E)S B = MAXIMUM TORQUE ANGLE ANGLE BY WHICH THE o CURRENT I LAGS THE VOLTAGE V
RESISTANCE (R)
LOCUS OF GENERATOR IMPEDANCE WITH LOSS OF EXCITATION
FiG.
FIG. 11.30 Loss of excitation phasor diagram
loss of excitation relay (LOE) picks up 40X operating ti mers 2A and 2B. Timer relays 2A and 2B are then 'sealed' by contacts 2A and 2BX and therefore time out irrespective of the loss of excitation relay. If timer relay 2A times out before timer 2B operates auxiliary relay 2BX, any operation of the loss of excitation relay will cause a trip signal to be sent by relay 40Y. Relay 40Y is self-sealing to ensure operation of the unit protection for fleeting operation of the loss of excitation trip relays. Operation of the unit protection trip relays will reset relay 40Y.
11.31 Loss of excitation relay operating characteristic
6.7 Pole slipping Pole slipping protection is only fitted subject to system requirements. Sustained pole slipping can cause: • Large fluctuations in voltage and frequency at the generator terminals which affect the station auxiliary power supplies, possibly leading to loss of boiler firing and/or failure of station auxiliary motors, followed by shutdown of the generating plant. • Large fluctuations in voltage and, to a lesser extent, frequency on the adjacent grid system which may produce disturbances on consumer loads and on other generating plant.
FIG. 11.32 Loss of excitation trip circuit
900
Generator protection uations in generator speed during pole the steam demand from the boiler, „ ,, u of • 1, resulting in loss of control of boiler, with dzinitig.e to plant. Cflt l Wirria,ze io generators due to overheating stiess: also, mechanical damage to 311
siichronising. power to and from pole slip,,,,crItors, which may result in indiscriminate . of certain transmission protection, leading . ipping of circuits and further instability [r J.-..:onnection of supplies. response of conventional generation and ms will be uncertain under pole slipsyste and the rapid re-synchronising of a , `. I r on generator is unlikely, special protection but only where system design con1. 'r e provided, show that pole slipping is a possibility. of pole slipping protection is not 'a pplication ,:,:nlended to date as it may reduce the reliability • .jpply system. dipping protection is very complex and full ,:an be found in CEGB reports. h.; requirements are that when the system centre, iero, occurs anywhere in the zone from the Tarninals of the generator transformer to the gen. : tor a trip is initiated. I mpedance relays are provided • ,..;e.;1 that pole slipping has occurred. The protec: I , blocked if the loss of excitation relay has and started a trip sequence. The measuring are capable of detecting the first pole slip in %mile of 0.1% to 10%. Pole slipping counting are provided in the range 1-10, to initiate a trip a preselected number of pole slips as a back-up • ;t ole ,,li pping of other generators. In choosing the :1-, cr of pole slips, the machine capability must be :dered. All the relays are reset in a range 0-5 if no further pole slipping takes place before :; , re,elected number of pole slips has been reached. ['e protection is operated from current and voltage ortners at the HY and LV terminals of the gen. .t, , r Transformer. The relays on the HV side of the tn.tortners are directional only and limit the opera.• or one pole slip of the pole slipping impedance 10 the zone mentioned above. .
stator water is cooled by distilled water in the water/ water coolers. The stator water also passes through strainers and an electrical heating unit. After leaving the stator winding and neutral terminals of the generator, the water flow is measured, using an orifice plate. The orifice plate is provided with a duplicate arrangement of pressure switches, using four pressure switches arranged so that two must operate to trip the unit. If the water flow through the stator fails when the generator is excited, then action must be taken quickly to prevent overheating. Loss of stator water flow is detected by differential pressure switches, which measure the differential pressure across the metering orifice plate in the stator water outlet pipework. An additional set of indicating pressure switches is arranged to give an independent alarm. The duplicated pair of two pressure switches activates two timers, one set for a 10-second delay and the other for a 20-second delay. If at the end of the 10-second delay the standby pump has failed to return the stator water flow to above the 80% threshold, then the third emergency pump is started. If starting the third emergency pump fails to restore the water flow to above 80%, operation of one of the duplicate pair of pressure switches will trip the turbine after the 20-second delay. This duplicated arrangement, apart from providing protection redundancy, allows the on-load testing of each pair of switches in turn. It is to be noted that three pressure switches can provide the same protection,
using a 'two out of three' arrangement to trip, and this has been used on recent installations. The tripping of the turbine steam valves shed load and, because of the margin of thermal capacity in the generator, the 'stator coolant flow low' protection can operate through the low forward power relay.
,
3 Loss of stator water flow :Ilockr n high rated generators, i.e., above 200 MW ' ' "
the stator winding is cooled by the circulation conductivity water; the water being pumped h the stator windings and a water/water cooler
• "C of two 100% duty electrically-driven stator water l' rs. the other being on standby. These pumps have .iitomatic changeover feature. In addition, there 4, turi her emergency stator water pump supplied with • • t from a separate direct current source. The n
6.9 Hydrogen temperature high This protection trip is not provided on all generators. Alarm only is given on some generators. The rotor circuit is cooled by hydrogen gas. This hydrogen gas is cooled by the common water cooling circuit which also cools the stator water. Failure of the gas flow circuit or restriction of the cooling water causes the temperature of the hydrogen gas to rise. Reduction of load could reduce the temperature to a safe condition, providing that the operator has, depending on the generator design, time to take corrective action. If however, there is insufficient time, then an automatic trip of the turbine is required, with unit tripping through the low forward power relay. The thermal capacities are such that the latter is acceptable. Warning of a gradual blockage of water cooling systems is given by an alarm at a temperature setting below the trip getting. It is unlikely that gas failure will occur but the differential pressure across the cir901
Protection culatory fans is measured and an alarm is initiated, if the pressure falls below a preset value.
6.10 Hydrogen/stator water cooling flow A failure of the common water coolant flow for both hydrogen and stator water causes a temperature rise in both circuits. If the time constant of the rotor cooling circuit is such that this will reach a dangerous condition before the stator circuit, then measurement of hydrogen temperature protects against loss of the common primary coolant. If, however, the stator circuit temperature reaches a dangerous condition first, then additional protection is required to monitor stator water temperature. The method adopted by the CEGB is to monitor stator water temperature on the discharge line from the generator. A Category A trip of the unit is required, as the time available for the operator to take action is too short. 6.11 Excitation failure The rapid advance in the technology of semi-conductor devices has led to their use in excitation systems employing AC exciters. Rectifier systems used, consist of a number of three-phase full wave rectifier sections connected in parallel and designed to give adequate reliability over long periods. Protective devices include fuses to protect the diodes from damage by overcurrents, and resistance/capacitance networks to suppress voltage surges appearing across the diodes. Three basic types of transient are likely to affect the rectifiers in an AC excitation system: (a) Field forcing. (b) Induced current surges following a sudden shortcircuit at or near the generator terminals, or from faulty synchronising. (c) Voltage surges due to rapid flux changes in the rotor magnetic circuit when the rotor winding is effectively open-circuited. The firs, :wo can be catered for by suitable choice of the voltage and current ratings of the diodes. The fuses protecting the diodes are designed to clear safely if a diode cell failure occurs during the transient defined under (c) above. The rectifier system is designed so that two parallel sections of a bridge arm can fail without interfering with the operation of the generator. If more than two paths fail, this will result in a shortcircuit of the bridge arm because of diode overcurrent. Rectifier bridge arm protection therefore operates if more than two paths have failed; it immediately trips the main exciter field circuit-breaker and sends a trip to the unit protection system through the low forward power relay, Note that this protection operates for short-circuits either on the AC or DC, or between 902
Chapter AC and DC, of the rectifier bridge and also for inter. phasefaults on the exciter winding. Loss of excitation protection will operate if the rectifier bridge arm protection fails to operate and excitation failure has occurred. All excitation faults initiating a trip of the main exciter circuit-breaker also initiate a trip to the un i t and do not wait for the loss of excitation protection to operate.
6.12 Motoring of the generator If the steam supply to the turbine is cut off, with th e electrical generator left connected to the system, then motoring will take place. This means that the generator acts as a synchronous motor and draws power from the grid system. In this situation, the turbine-generator continues to rotate at synchronous speed and, if a l. lowed to persist for too long, the turbine blades may be damaged. However, with the protective arrangements described in this chapter, the circumstances giving rise to motoring are likely to be most infrequent in the life of he unit, since all of the faults listed on the logic diagrim (Fig 11.35) will be cleared by opening the HV and generator voltage circuit-breakers before motoring can take place. Those protective devices which operate through the low forward power relay should trip the circuit-breakers when the forward power is about 0.5 07o of full load ( MW). The main danger arises if the low forward power interlock relay fails to close due to malfunction; if so, operator action is necessary to disconnect the generator safely from the system.
6.13 Emergency pushbutton Operation of the emergency pushbutton will initiate the tripping of the turbine steam valves and, provided that these valves close correctly, the remaining main plant will be tripped via the low forward power relay interlock. If the relay contacts do not close, then the operator must take the necessary action for dealing with the emergency such as tripping the unit auxiliaries. The boiler firing is tripped automatically from loss of relay fluid pressure. Inserting the low forward power relay interlock in the tripping circuit of the pushbutton, reduces the risk of the operator opening the generator HV circuitbreaker if the emergency is caused by the turbine valves failing to close properly.
7 Generator transformer and unit transformer protection The generator and unit transformers can be subjected to a number of faults which require an immediate trip of the unit in order to limit the damage to the
Generator transformer and unit transformer protection transformers. These are phase to phase faults and earth faults on the windings, interturn faults (possibly on end windings caused by line surges), core faults due titv o core insulation Failure, failures of the cooling system t ank faults causing loss of oil and consequent an d t jangerous conditions. Faults external to the transoleners, if not cleared quickly, cause overheating and ,nechanical .stress. ace provided to remove the transProtective orrners from the grid system should any of these faults oceur. Some of the protection systems are arranged to „ke a prior alarm of a possible dangerous condition jeveloping.
tions or on the generator that could be cleared by opening the generator voltage circuit-breaker. In addition, the setting has to remain stable for magnetising in-rush currents, since the generator transformer can be switched in from the HV side with the generator voltage circuit-breaker open. This protection complements the protection for the HV feeder and the generator transformer. It also complements the protection for generator terminal phase faults for directly connected generators.
7 . 1 Phase to phase and earth fault protection
The inverse time overcurrent protection provides backup for all 1-IV and LV winding faults and auxiliary system faults. As the inverse time protection has to grade with the 11 kV interconnector protection, the operating times for HV terminal faults are long. High set overcurrent protection is therefore provided to give fast clearance for these faults and arranged to operate into tripping system 2, whilst the IDNIT overcurrent protection operates into tripping system I (see Fig 11.35). Relays with low transient overreach are provided and set to remain stable for LV faults. A Category A unit trip is required. The definition of low transient overreach as applied to high set overcurrent protection is as follows: The overreach (OR) is the difference between the RMS value of the steady state current to operate the relay (I s ) and the RMS value of current which, when fully offset, will just operate the relay (10), expressed as a fraction of (L, p ), i.e.,
phase to phase fault protection of the generator transformer and unit transformer is provided by biased differential protection (described under generator protec tion) and, where the generator is directly connected :a the generator transformer and unit transformer, the protection of the generator transformer includes the g enerator stator windings and LV connections. The unit transformer has its own biased differential protection. Earth fault protection of the LV windings of the aenerator transformer, the HV windings of the unit transformer and the connections between, is included in the stator earth fault protection (see Sections 6.1 and 6.2 of this chapter, 'Generator stator earth faults'). Earth fault protection of the generator transformer high voltage winding and the low voltage winding of the unit transformer is included with the biased differential protection of each transformer (see Fig 11.23). When a generator voltage circuit-breaker or switch disconnector is provided, there will be no infeed from he generator with the switch open. In this case, the HV earth fault relay impedance could cause saturation of the 1-1V side interposing CTs and prevent operation of the biased differential relay. Electrical protection for earth faults is therefore entirely dependent on the HV earth fault relay and so the relays are duplicated.
7.2 Generator transformer HV inverse time and high Set instantaneous overcurrent The inverse time overcurrent protection is provided as a back-up protection against system infeed to a generator circuit fault not cleared by main protection. The high set instantaneous overcurrent protection is supplied from the same CTs as the inverse time overCurrent protection and located at the HV circuit-breaker, Providing protection for as much of the generator Circuit as possible. The setting must be high enough to remain stable for faults external to the generator circuit but low enough to detect some generator faults at Conventional power stations. Where a generator voltage circuit-breaker is provided, the high set overcurrent protection must not operate for faults on the connec-
7.3 Unit transformer HV inverse time and high set instantaneous overcurrent
OR = (Is — Iop)/lop
or
f o p = Is/(OR + I)
Referring to Fig 11.35, if the unit transformer is 60 MVA with a reactance of 15 0/o, a fault on the LV side of the transformer will be 60/0.15 MVA 400 MVA. If the quoted overreach for the relay is 5 %, then the fault (expressed in MVA) to cause relay operation is 400/1.05 MVA. So, to remain stable, the relay must be set greater than 1.05 x 400 MVA and CEGB practice with this type of relay would be to use a factor of 1.5 (i.e., 600 MVA setting) on a through fault of 400 MVA.
7.4 Standby earth fault This provides protection for earth faults on the unit switchboard busbars or between the unit transformer circuit-breaker and its associated current transformers and back-up protection to the transformer LV windings and connections. Standby earth fault relays are set to grade with all 11 kV interconnector earth fault protection. Since for nuclear power stations, the supply to the auxiliary system is arranged so that it is possible to 903
Protection lose a unit supply and still continue operating, the HV overcurrent and standby earth fault protection must be two stage. The first stage is arranged to trip the unit transformer circuit-breaker only, with the second stage tripping the unit directly. For all other stations, the standby earth fault relay trips the unit transformer circuit-breaker, followed by a unit trip through the low forward power relay. The overcurrent protection becomes a Category A trip. 7.5 Generator transformer and unit transformer internal faults Buchholz protection is provided for faults which do not immediately affect the line currents to the transformer. Examples of these faults are: • Hot spots due to core insulation failure. • Faulty joints. • Interturn faults. These faults produce localised heating, causing decomposition of the oil and a release of gases. The gases are detected by the Buchholz device connected in the pipe to the conservator. The protection also provides an alternative protection for phase to phase faults and some winding earth faults. For a detailed explanation of Buchholz protection, refer to Volume K, Chapter Ii. 7.6 Winding temperature Transformer ratings are based on the temperature rise above a defined maximum ambient temperature and so a degree of overload can be tolerated at lower ambient temperatures and for certain load cycles. However, with generator and unit transformers, there is little chance of accidental overload, as they are both under supervision and are designed to meet the maximum unit auxiliary load and generator capabilities. Overloading from fault conditions is prevented by the protection systems already mentioned. Some protection, however, must be provided to detect an over-temperature condition caused by a major breakdown in the cooling system, at first initiating an alarm for the operator to start the standby cooling equipment. If the temperature continues to rise to a dangerous level, isolation of the transformer is by a unit Category B trip which opens the HV circuit breaker. For those stations where it is possible to lose a unit transformer supply and still continue operating, a trip of the unit transformer LV circuit-breaker may remove the over temperature condition on the unit transformer. This does not apply to the generator transformer, which must be isolated from all supplies. Unit transformers with natural cooling require a winding temperature alarm only. An overload of the 904
Chapter 11
unit transformer can be experienced during paralleling of auxiliary switchboards but other protection arrange. ments, such as alarms (if paralleled for longer than 10 minutes) and operating procedures, guard against this condition. Over-temperature conditions can be detected by th er mal image techniques and reference should be made to Chapter 3 on transformers. 7.7 Conservator gl ow oil level' alarm All water/oil cooled transformers (of 200 MVA and above) connected to 275 kV and higher voltage levels, and all units at nuclear power stations together with their associated unit transformers, have additional protection to safeguard the unit against loss of oil. Transformers not covered by a low level alarm are protected to a limited extent against low oil level by the Buchholz gas and oil actuated relays. 7.8 Pressure relief device alarm The purpose of this device is to relieve tank internal pressure during fault conditions and thereby reduce the possibility of damage to the transformer tank. The device has output contacts, which may be arranged to initiate a trip or alarm. 7.9 Freezer air drier alarm This protection is fitted to all generator transformers operating at 132 kV and above. An alarm only is required. An alarm is also required to indicate loss of electrical supply to the equipment. 7.10 Overfluxing During run-up conditions, a failure of both automatic voltage regulator (AVR) channels in automatic control, or incorrect operation whilst under manual control, can cause overfluxing of the generator transformer and unit transformers. A control is provided as an integral part of the AVR. This control, however, does not operate when the AVR is on 'manual' and may also not be effective above speeds near to synchronism. Overfluxing relays, which measure the ratio of voltage to frequency, are therefore provided for protection of the generator and unit transformers in all modes of excitation control and also when the transformers are connected to the generator alone. Overfluxing of the transformer when connected to the system is rare, but it is particularly vulnerable to overiluxing during commissioning tests or the testing of the excitation equipment. A direct trip of the main exciter circuit-breaker is therefore required when any switch disconnectors or circuit-breakers on the [-IV side of the generator trans-
HV/LV connections and generator voltage/ HV circuit-breaker protection former are open and all switch disconnectors and circuit breaker's closed on the LV side. This is achieved by using monitoring relays to indicate the position t h e RV and LV circuit disconnectors or breakers d automatically switching-in the protection when the an [cans formers are connected to the generator but not he system• Some excitation systems have a time lag between a ii ait h y AVR taking o% er from a faulty one, i.e., those os i n g a main and standby AVR. For these systems, the e. setting for the overfluxing relay to trip the main Lim iter circuit-breaker must not be less than the time for this changeover to take place.
8 Station transformer protection The station transformer is protected by a Buchholz re lay with alarm and trip contacts, a winding temperatu re and pressure relief device both set to alarm and a conservator tank low oil level relay, also set to alarm. Protection against phase faults is provided by an overall biased differential scheme which meets the same equirements as the generator/generator transformer r o verall biased differential protection. This protection includes restricted earth fault protection for both the NV and LV windings. Back-up protection consists of one ordinary inverse and three high set overcurrent relays. The ordinary inverse relay apart from operating on transformer ‘vinding faults, provides back-up protection for the 11 kV supply system and so has to grade with the protection on this system. In the event that this protection is operating for an uncleared fault on the II kV supply system, the protection is made two stage by means of a time delay relay. The first stage trips the 11 kV circuitbreaker and the second stage (0.3 second delay) will initiate a unit trip. A guard relay is required to allow he close grading between the first and second stage of 0.3 s. Back-up earth fault protection of all 11 kV system faults is provided by two single-pole relays operated from a current transformer in the neutral of the transformer LV winding. The protection is again in two tages. Both relays are ordinary inverse relays but are set to grade in the same way as the high voltage (11 kV) evercurrent protection.
,
9 HV/LV connections and generator vottageHV circuit-breaker protection 9
.1 Phase to phase and earth faults
The connections between the HV circuit-breaker and the generator transformer HV bushings are protected bY two independent high speed fully discriminative Protective systems. They are referred to as 'First Main Generator Feeder Protection' and 'Second Main Gen-
erator Feeder Protection'. The protective systems employed are of the differential circulating current type described earlier under 'generator protection', utilising high impedance relays, where pilot lengths are less than 600 m and an approved form of pilot wire protection using British Telecom type pilots, on lengths over 600 m. The connections between the generator and the connected transformer windings are protected by differential high impedance circulating current protection as previously described under 'generator protection'. Reference to Fig 11.24 shows that balancing CTs provided when using biased differential protection (Fig 11.26) are omitted. When allocating a setting to the protection, therefore, a check is made that: • The setting is above the maximum fault current for a fault on the LV side of the unit transformer. • At minimum earth fault levels, the operating voltage across the relay is twice the setting.
9.2 HV circuit-breaker faults System faults on the generator HV circuit-breaker are cleared by the busbar protection. This protection is arranged to trip the unit directly, in addition to the circuit-breaker, for all stations except where special provision has been made for the unit to have a runthrough capability (i.e., nuclear power stations). A failure of the circuit-breaker to open, caused by a control system or mechanical linkage fault, must trip the unit directly. The reasons for tripping the unit are given in Section 4 of this chapter on 'boiler protection'. If the generator HV circuit-breaker fails to open to clear a generator circuit fault, then all circuits connected to the same section of busbar are tripped. 9.3 Generator voltage circuit-breaker or switch disconnector Where a generator voltage circuit-breaker is used to isolate the generator for certain fault conditions, the appropriate protection arrangements have been mentioned previously in this chapter. Additional protection is, however, required to deal with the situation arising if the circuit-breaker fails to operate to clear a fault when asked to do so. In these circumstances 'circuitbreaker fail' protection, which detects current flow following operation of a trip relay, ensures That the fault is cleared by a direct trip of the unit via the generator [-IV circuit-breaker. Phase discrepancy protection is also provided for the generator voltage circuit-breaker to detect when one or more phases are out of step, because these circuit-breakers comprise separate isolated single-phase interrupters and the three phases open and close without mechanical interlinkage between phases. It detects malfunction of the circuit-breaker for any opening or closing operation by monitoring the auxiliary switch 905
Protection position of each phase. The protection acts either directly into the pneumatic system of the circuit-breaker or makes a second attempt at tripping the circuit-breaker. It trips the 400 kV circuit-breaker if, after a delay, the generator voltage circuit-breaker is still out of step, through the circuit-breaker fail protection which is provided on the generator voltage circuit-breaker. Thus, following a failure to open correctly for a trip on fault, the 400 kV circuit-breaker is opened. The circuit-breaker fail protection must operate as fast as possible discriminating only with the main protection. No discrimination between the phase discrepancy protection and the circuit-breaker fail protection is required.
10 Pumped-storage plant protection Protection details given in this section are based on experience of one type of hydro-electric power station: the pumped-storage plant at Dinorwig. The layout of the connections and protection is shown in Fig 11.33. The protection of the transformers and connections are as at a conventional station since these only are required to operate in the normal frequency range. However, unlike conventional stations, the synchronous machines at Dinorwig operate either as motors or generators depending on system requirements. They normally pump at night, when demand is low, and generate for periods during the day to meet peak load conditions or outages of other generating plant. The station has a complex generator voltage 18 kV system, with protection operating over a wide range of frequencies, the machines being excited at increasing and decreasing frequency during start-up or run-down sequences. Consequently, special protection had to be provided for this purpose. Due to instability, some protection systems are switched out by a frequency relay outside the reliable operating frequency range and the conventional protection takes over. The complete protection system is not described because of its complexity: only the salient features are highlighted. The Dinorwig system (Fig 11.33) has a highly selective starting system, which either provides variablefrequency synchronous motor starting supplies from one of two variable-frequency rectifier/inverter supply systems, or starts by using another machine as a generator in a 'back to back' arrangement. The generator transformer, in addition to coupling each machine to the 400 kV system, provides a supply to the .many auxiliary supply transformers. The transformer and generator protection systems for normal frequencies are the same as for conventional stations, using generator voltage circuit-breakers but special protection is provided for operation outside the 47-51 Hz frequency range. There are only two protection systems in this variable frequency category; one is the overcurrent protection for the starting busbars and the other is the machine differential protection, which was specially designed to provide low current settings at 906
Chapter 11 the low frequencies. These two protection systems are switched out when the machine is up to normal fr e quency. The other protection systems operating out s id e the normal frequency range which are not switched o ut are: • Voltage operated stator earth fault (explained under generator stator earth faults). • High set earth fault (generator neutral). • High set earth fault (unit transformer HV neutral), Note that here the matching transformer is not under oil and that additional protection is required. • Dynamic braking overcurrent. The first three have already been explained in Section 6 of this chapter. The fourth applies only to Dinorwig and is now explained.
10.1 Dynamic braking overcurrent protection In order to bring the generator to rest quickly and allow a restart either in the same mode or in the revers e mode, a three-phase short-circuit is applied to the machine terminals. The current is limited to be within the normal machine current. A dynamic braking overcurrent relay, set above full load current, protects the machine should this switch be applied incorrectly or the control system develops a fault (Fig 11.33). In addition, for an electrical fault on the generator, an inhibit signal is provided from the protection to prevent application of the dynamic braking switch. For all other fault trips, a signal is sent to ensure safe shutdown of the unit. Because of possible overspeed of the turbine up to 76.5 Hz and the system requirement to operate down to 45 Hz, all generator protection, i.e., protection in service when the generator circuit-breaker is open, must operate correctly over this frequency range. Special protection is provided during starting sequences. All other protection must operate up to 52 Hz (over frequency trip level). For a controlled shutdown, i.e., unloading before opening the LV circuit-breaker, the trip signal to the LV circuit-breaker is either from auxiliary contacts indicating main inlet valve (MIV) or guide vanes (CV) closed or from a time delay relay set between 0-10 seconds; setting, to be determined, must be greater than MIV (or GV normal closing time).
10.2 Under frequency protection In the pumping mode, protection is provided to prevent operation below 49 Hz (Fig 11.34). It is also a system requirement that all pumps must be tripped if the frequency lies in the range 49.0-49.5 Hz. This is necessary if the system frequency is low due to insufficient generation, hence requiring any units which are pumping to be tripped.
Pumped-storage plant protection
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Protection system for Dinorwig pumped storage plant — simplified schematic
Pumped-storage plant protection
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SYNCHR.ONiSING
VAR I REACTIVE POWER GENERATOR-MOTOR 2 TRANSFORMER PROTECTION SYMBOLS TO UNITS 3-6
BUCHHOLZ I2-FLOAT) PROTECTION
TO 11kV STARTING BOARD 3 (5 OIL TEMPERATURE NOTE. THIS CIRCUIT REPEATED THREE TIMES TO PROTECT SIX GENERATOR MOTOR UNITS
0415I T SERV CES
acABo
2
1
(5 DIFFERENTIAL PRESSURE
t1,5 CT LOST LOAD
FIG. 11.33 (coni'd)
, SHEET Ti
Protection system for Dinorwig pumped storage plant — simplified schematic 909
Protection
Chapter 11
FREQUENCY RELAY
STAGE I
TRIP SIGNAL 7 0 THE 'GENERATOR VOLTAGE CIRCUIT SPEAKER
52 Hz
STAGE 2 < 49 Hz c
FIG.
E
TRIP SIGNAL TO SHUT DOWN THE UNIT PUMPING MODE ONLY
11.34 Over/under frequency protection
An under frequency relay is 'set nominally at 49 Hz for both these duties. Two frequency output stages in the same relay are used and arranged to trip the generator voltage circuit-breaker. The frequency relay is configured to measure system frequency, i.e., it is connected to the VT at the 18 kV terminals of the generator transformer. Note that each frequency relay has four output stages which can be set for a combination of 'over' and 'under' frequency protection.
10.3 Over frequency protection The turbine and generator are capable of operation up to 750 r/min (75 Hz). The overspeed protection and control in the governor and the response of the guide vanes in closing, may cause transient overspeeds of 76.5 Hz under load rejection. To protect generators connected to the same system as the Dinorwig machines from overspeeding, over frequency protection is required to trip the Dinorwig machines by opening the generator circuit-breaker at a frequency of 52 Hz. To enable synchronisation to be established as soon as possible after overspeeding, the excitation is left on and the machine is brought under control by governor action, tripping of the main and governor valves occur910
O
ring only at excessive overspeeds. Note that protection associated with the generator will therefore have to function correctly up to a maximum of 76.5 Hz. A frequency output stage in the same frequency protection relay as that used for under frequency, is used in the over frequency mode (see Fig 11.34) and a trip of the generator voltage circuit-breaker is provided. The relay setting is 52 Hz. Failure of the VT secondary fuse in the supply to the frequency relay is arranged to bring up an alarm but not to initiate a trip.
10.4 Overspeed in excess of 10% Following a loss of load, the turbine speed will try to rise above 55 Hz because of the overall response of the governor system (including the inlet guide vanes closing). If the governor system functions correctly, 7 then the turbine speed will start to fall below 110' 10 overspeed. Protection of the turbine is required if the governor system fails. This is achieved by a trip signal derived from three electrical speed switches operating through a time delay relay (0-30s) which allows time for the governor control system to act to bring the turbine under control. The generator voltage circuit breaker is tripped after the time delay relay operates,
Pumped-storage plant protection failure of the governor control system to the speed. ing a onmp-turbine start-up, a protection trip Dur from the turbine control system is sent if the r being started reaches a speed in excess of 110%. 1, w
:11
1
,1k:zing a
0.5
Loss of pumping power
power fails whilst the machine is in the pumping j c ,thC water flow reverses in the turbine, causing vibration from an uncontrolled reverse water An immediate trip of the unit is needed to close main inlet valve and bring it to a safe condition. A relay is provided to measure output power from enerator: this is interlocked with an auxiliary g on the inlet guide vanes such that it is only lied when the inlet guide vanes are open. The setting j , s( below the power required for the condition when main inlet valve is open and the runner watered. n i [s power level is estimated to be 63 MW.
10.6 Emergency stop pushbuttons emergency stop pushbuttons are provided, one looito the turbine-generator and one on the control desk. 10.7 Overvoltage ilc,:ause of the overvoltages expected if Dinorwig is .olated from the main system, with either or both ':[ies to the substation at Pentir still connected, and 'he capacity of the generator-motor/pump-turbine to erspeed by 50%, an instantaneous overvoltage relay used to protect the supply transformers connected i J 18 kV. The setting is 130% of nominal voltage. Overvoltage protection for the generator is provided ti the AVR and is set for 120%. It is inhibited when le machine is synchronised to the system. 10.8
Excitation equipment protection
Protection of a sustained DC short-circuit is provided
a definite time overcurrent relay operated from CTs n he 3.3 kV circuit-breaker, tripping that circuitreaker only. Thyristor short-circuits are taken care by the thyristor fuse. All cable phase faults from 're excitation transformer to the 3.3 kV circuit-breaker nid all LV winding phase faults are detected by the 1 IV (18 kV) extremely inverse overcurrent relay. Over,Jirrent protection on the excitation transformer pro'Js back-up protection of the excitation equipment. Protection co-ordination must take account of the airrent/time characteristic of the machine field, as well 1 ■ that of the fuses protecting the thyristors. 10,
9 Stator cooling air over-temperature
Ihe stator is air cooled, with water cooling the air.
Operator action only is needed for 'stator water coolant flow low'. A trip initiation is, however, required for high stator cooling air temperature. The temperature detector is set to operate at a temperature of approximately 65 ° C. The inherent thermal capacity of the machine allows for unloading before initiating a unit trip, i.e., the guide vanes are closed before tripping the generator voltage circuit-breaker. Interlocking duty by the guide vanes compares with the low forward power interlock on fossil-fired and nuclear stations and is achieved by the DC tripping system.
10.10 Bearing temperatures and oil levels The guide and thrust bearing temperatures are monitored and an automatic unit trip initiated, after first closing the guide vanes, if temperature limits are exceeded. 10.11 Back to back starting protection During back to back starting, protection is required against three conditions: • Generator runaway. • Incorrect excitation levels on the generator-motor. • Excess heating of the stationary field winding in the event of failure of a generator-motor to start. 10.11.1 Generator runaway
This condition can result from: • Incorrect excitation. • Excess generator accelerating torque. • Excess motor retarding torque. This protection is achieved by setting an overcurrent relay operated from a CT in the tee-off to the starting system (Fig 11.33). This is designed to trip the unit if the current exceeds 8000 A for longer than 30 seconds, or to trip instantaneously if the current exceeds 21 000 A. The basis for the settings is that if the two machines 'lock' together on a back to back start, the current will fall below 8000 A before 30 s and will never exceed 21 000 A. So if the current exceeds 21 000 A (approximately 2 x full load), this indicates an electrical fault on the starting busbar system: hence this protection deals with busbar faults. At the design stage, busbar protection was considered, i.e., a balanced system of protection, but with the added complexity of trying to obtain a balance at low and nominal frequencies it was likely to be unreliable. The instantaneous overcurrent relay is more reliable although not as discriminative. However, with the high integrity designed into the starting busbars, using air insulated and isolated connections, a busbar fault is very unlikely to OCCLIr.
911
71IP■ Protection
Chapter 11
10.11.2 Incorrect excitation levels on the
10.13 Station transformer
generator-motor
The protection arrangements are similar to that for a normal transformer on a fossil-fired station, ex cept that the HV winding earth fault protection is included in the generator HV earthing protection system and the 18 kV connections to the HV winding are included in the 18 kV connections protection.
For a back to back start the generator excitation level is set to 1 p.u. and the motor excitation to 0.8 p.u. (I p.u. excitation is the excitation for the nominal voltage with the machine on open-circuit). The various conditions of incorrect excitation are: (a) No generator excitation, 0.8 p.u. motor excitation. b) 1.0 p.u. generator excitation, no motor excitation. Protection is required to limit motor damper cage overheating. (c) Failure/deviation of either excitation set point during run-up. Since failure to start is inevitable for (a) and (b) and probable for (c), maladjusted excitation settings are arranged to trip. All three conditions are detected by conditioning the start signal such that excitation in both machines has to be correct before a start can be in 10.11.3 Excess heating of the stationary field winding in the event of a failure to start of generator-motor
This protection is provided by monitoring the starting ti me from the field circuit-breaker closing until the machine is up to speed. The starting time allowed by the protection must be compatible with the inverter starting time, to avoid the need for separate protection for both starting modes.
10.12 Excitation transformer Earth fault protection of the 18 kV winding is included in the unit transformer earth fault protection scheme. Earth fault protection of the LV winding is part of the excitation equipment earthing which consists of high impedance earthing through a resistor. To prevent voltages being transferred through interwinding capacitance coupling, an earthed screen is provided between windings. The transformer windings and connections are protected by an extremely inverse relay and two high set overcurrent relays. These relays initiate a Unit trip. The extremely inverse relay used for this protection has to grade with the fuses protecting the excitation thyristors. All excitation transformers have a Buchholz gas (alarm), a Buchholz gas (trip), a pressure relief device (alarm) and a conservator tank low level (alarm). The excitation transformer is naturally cooled so the winding temperature indicator gives an alarm only. All the protection systems mentioned above, depending on circuit conditions, trip their own unit, the banked generator-motor unit, the 400 kV circuit-breakers and send a trip signal to the starting busbar system to trip the generator-motor, if they are in a starting sequence.
912
10.14 Starting transformers Starting transformer 1
The protection of starting transformer I is the same as the station transformer. Starting transformer 2
Starting transformer 2 i s connected Dynll and will require the same protection as the starting transformer 1, except that the secondary circuits of the overall protection CT allow for a delta/ star transformer instead of the star connection on starting transformer 1.
10.15 Starting equipment The starting equipment comprises an input and ourF.ut transformer stepping down to 3 kV, thyristor-controlled rectifiers and inverters and a DC link, including a DC circuit-breaker. 11 kV protection on the input to the rectifier transformer includes three-pole extremely inverse overcurrent relays, two-pole instantaneous high set overcurrent relays and a single-pole high stability earth fault relay. Overall biased differential protection is also provided. Protection of the 18 kV side of the inverter transformer is three-pole extremely inverse overcurrent relays and two-pole instantaneous high set overcurrent relays. The 18 kV overcurrent protection CTs are located between the 18 kV transformer disconnector and the 18 kV transformer winding. Protection of the thyristors is by fuses and there is protection to detect asymmetrical currents caused by thyristor or control failure. Current asymmetry protection is provided both on the input to the rectifiers and the output of the inverters (i.e., on the AC side of both). Protection against DC short-circuits is provided by a two-stage definite time overcurrent relay, the first stage suppressing the starting equipment, the second stage tripping the 11 kV ACB on the starting transformer after a time delay. It must grade with the thyristor fuses and the rectifier transformer HV overcurrent. Both transformers incorporate a Buchholz gas (alarm and trip), an oil temperature (alarm) and a pressure relief device (alarm). In addition to the above the rectifier/inverter equipment has undervoltage protection to detect loss of supply. The trip to the 11 kV circuit-breaker is delayed, to allow the starting equipment to shut down and attempt to clear the fault for the following protection:
Pumped-storage plant protection
__
pr0tti0n on the rectifier and urri
stage o1 the ov currt protection on the the rectittemn to supplY faults for the rectifier/inverter
ju\ iaIY
I
: 16 Protection during starting during starting when the frequency is requires special consideration. During startnachit1 terminal voltages are proportioned for cnnstant excitation, whilst machine -. rintS are almost independent of frequency for jnt ecitat10. Voltage transformers will perform only under these conditions, whereas CTs and designedl for 50 Hz working do flOt. Therefore, and phase to phase faults, and also earth faults, at a time when the neutral resistor : hed over or is shorted out, some form of special js needed. Starting protection is provided to • .. phase to phase faults (earthed or unearthed) : as low a frequency as possible. A non-dis'natLe form of protection is the minimum requirefor plant protection. A protective relay using a • :Hcd input (and therefore independent of frequenj used for low frequency operation and is switched • • boe a frequency of 45 Hz to prevent operation ir ough-falilt conditions when the system frequency Flz and the machine is synchronised, A selective scheme of the starting busbar trip system must ioIate connected plant from the faulted zone. l r earth faults, limited by the machine neutral n ng resistor, fault currents are limited to 10 A as • o,sil-fired stations, by the resistance in the dis:iion transformer secondary circuit. Special proon is therefore not necessary for the following 'oils: • I ic ne •
machine can be operated with an earth fault until operating frequency of the protection is reached.
He
magnitude of earth fault currents falls with cqueney as the earth fault ioop is predominantly nI':lve and the ratio of voltage to frequency is pt Constant.
• Iii nine delay for unloading is not required during e start-up period, therefore the tripping can be 1'.de instantaneous when the operating zone of the 'rotection is reached.
.'2 '
Protection of the pump-turbine and e upper/lower reservoirs
CCtiOn lists the Category A and Category B trips designed to protect a pump-turbine installation as that used on the Dinorwig pumped-storage i.e., they are typical only for reversible pump. iflCS Using guide vanes. .ir
10.17.1 Category A trips
Category A trips result in an emergency shutdown of the unit and include the following areas of protection:
• Governor air/oil receiver oil pressure low Operates to trip the unit when there is only a sufficient volume of fluid available to close the guide vanes (GVs), and hold them closed without the release of air into the control air pipework. • Governorpilotoilpressurelow This trip is initiated if oil pressure to the pilot servomotor falls to the minimum safe level. This level is set below the 'low pilot oil pressure' at which the actuator is automatically switched from 'Auto' to 'Manual'. • Governor supplies failure and electrical governor fault These trips are monitored and conditioned within the electrical governor. A common signal is initiated to trip the unit when the governor is in control and a loss of electrical supplies, or a fault occurs, which prevents the governor from controlling the turbine. • Electrical overspeed The unit is tripped if the turbine overspeeds and the governor fails to compensate within a preset time. This time is adjustable over a 0-30 s range, thus avoiding possible damage to the wearing rings caused by vibration under prolonged running at overspeed. • Draft tube valve (DTV) not fully open and DTV oil pressure low These trips primarily safeguard the pump-turbine against damage caused by operation under cavitation conditions in the pumping mode, although the trips are operative in all modes. The DIV movement is the final protection. The loss of oil pressure trip normally operates before the DIV starts to close, enabling the unit to be brought to a safe condition before the inevitable closure of the OTV. • Water churning protection This trip protects against running the pump-turbine in water with either the main inlet valve (MIV) or the GVs closed, in any condition other than the transition from spin modes to operational modes. • Governor air/oil receiver level low This feature supplements the governor air/oil pressure low trip and also covers for the eventuality of an incorrect air precharge pressure causing air entrainment in the control oil pipework. • Excessive/partial G V opening and pump speed protection To avoid pump water flow instability conditions in the pumping mode, the pump speed/head characteristics require the GV opening and pump speed to be within prescribed limits. Trips are provided to avoid vibration damage if the pump operates outside these limits. 913
Protection
Chapter 11
10.17.2 Category B trips
Category B trips result in a controlled shutdown of the unit and include the following areas of protection: • GV out of step This protection is initiated if blockage of, or damage to, a single GV causes it to move out of step with the other GVs. • G V start position 2 exceeded with generator circuit-
breaker open If, under starting conditions, 'start position 2' is exceeded after the turbine has attained 90 0 '0 speed, the unit is shut down because turbine acceleration would not be reduced and synchronising would not be possible. • Suction cone water level high In the pump start and spin modes, a unit shutdown is initiated if the water level under blowdown conditions is too high to permit the pump-turbine to spin in air only.
• Shaft seal cooling water flow low seal wear
Protection against
• Wearing rings cooling water flow /ow Failure of cooling water flow to the wearing rings when operating in pump start or spinning in air modes, causes the unit to shut down to prevent damage to the wearing rings and possible damage to the rotor. • Wearing rings temperature high Additional protection against damage to wearing rings. • Bearing temperature (pads and oil) high. • Bearing oil levels low. • Main inlet valve (MIV) air/oil receiver oil pressure/ oil level low Operation of the unit in the pumping or generating modes requires the MIV to be fully open. fn the event of a loss of oil pressure the MIV would start to close under the action of the counterweights and a controlled shutdown is required. The low oil level trip backs up the low pressure trip and also prevents the release of air into the control oil pipework in the event of incorrect precharge for the air pressure and a controlled shutdown must be initiated. -
• Headgate, stopgate or tailgate closing Operation with gates closed (or closing) is unacceptable so the unit is shutdown under these circumstances. • Failure to establish cooling water flow at 10% speed This shutdown protection operates to prevent overheating of the various CW-cooled plant items. Above 10 07o speed an alarm only is raised which requires operator action. • MIV partially closed when G Vs are not fully closed In normal operation the MIV must be fully open, if it does start to close for any reason, the unit must be shut down. • M valve, P valve or F valve open The M and P valves are used during spinning in air modes; the 914
M valve drains water away from the peripheral chamber to prevent water build-up between the GVs and the runner, and the P valve bleeds air away from the spiral casing in order to prevent a build-up of air which would otherwise be passed through the system when normal operational modes wer e instituted. The F valve is used to bleed air out of the pump-turbine casing when making the transition from spin mode to operational modes. If any of these valves are open during pumping or generation, a controlled shutdown is initiated. • M valve and P valve closed in spin in ode If either the M or P valve is not open in the spinning in air mode, an unacceptable air and/or water accumulation can occur in the pump-turbine, the unit is therefore shut down. • Upper/lower reservoir levels high When the water level in the upper reservoir (pumping mode) or the lower reservoir (generating mode) reaches the maximum permissible level, the unit is shut down. • Sequence control faults A unit shutdown is initiated for any failure of the pump start-up sequence to achieve a given plant state within a predetermin e d ti me or number of operations. Possible causes Include excessive pump priming time, excessive pump loading time, second failure of pump synchronising or excessive pump start up time. -
• Air admission valve open in pump service or in the spin pump to pump transition On-load air admission is required during generation modes but is not permitted during pumping modes. In circumstances where the air admission valve is open during the pumping modes, the unit is shut down. • Blowdown air admission valves open in pump service or in the spin pump to pump transition If the blowdown air admission valves are open when the main pump isolator is closed and the MIV is not fully closed, the unit is shut down to prevent air admission to the system during pumping.
11 DC tripping systems 11.1 Logic diagram The logic diagram (Fig 11.35), which is typical of stations with a generator voltage circuit-breaker, lists all the unit trip-initiating devices and details which plant has to be tripped to bring the unit into a safe condition. The groups formed by plant items to be tripped are explained down the left hand side of the drawing. Group 1 and Group 3 contain the same plant items, except that Group 3 trips the steam generator and turbine first, followed by the other plant items via the low forward power relay. Group 1 is designated a Category A trip and Group 3 a Category B trip.
DC tripping systems r to cater for several primary circuit conor d e la acions an d to avoid confusion, the logic diagram following format: (he
.,„,ps 1 and 3 are always Category A and Category ci ecti‘ely, requiring opening of the generator • r We circuit-breaker to clear the fault. () also always Category A and 2 and 4 arc B but apply to those stations requiring ing of the generator voltage circuit-breaker open Ic r the fault, leaving the generator and unit cl
6fo ups
• ,
ea
,Iiisforrners connected. the four basic tripping groups. Groups 5, c arc e special but always maintain the same identity •1r ..,,pe,:tive of the primary circuit configuration. F a ji trip initiating device has a unique number and . , „ u mber is cross-referenced to the tripping schemaon Fig 11.36. The group numbers are also . , , , ified on both the logic diagram and the tripping • "
:2 1
..• mnatic. the turbine tripping shown on the top left hand side Fig 11.35 is typical of one manufacturer of turc. The turbine tripping sequence is described in ,,,rion 3.4.2 of this chapter and the figure shows the .1cliatic arrangement. CEGB practice is to draw a .,„: diagram first, which meets all the requirements •! ..iie station operations system, and the tripping sche•.2tic is developed from this.
11.2 Tripping schematic diagram ang completed the logic diagram, the next step is to "...pare a tripping schematic diagram (Fig 11.36) for
tripping system. Modern practice is to provide so separated tripping systems which are fundamentally same. In those cases where the protective relay -tern is not duplicated, e.g., biased differential prothen the tripping contacts are included in only of the tripping systems. the allocation of protection systems to each tripping is always the same. Figure 11.36 is arranged • h all the trip initiating devices, in groups as allocated he logic diagram, down the left hand side and the . put trip relays down the right. Where possible, trip. ,t functions are commoned on trip relays and opera:1 of several trip relays are required to perform a ".41) trip. The basis of the selection of a trip function a relay is to allocate all functions which have to lri ppeçl following the operation of the low forward %er interlock to the main tripping relays (sometimes - l ed the master trip relays). These trip relays are . laYs numbered 1 and 2. The turbine and steam genacr allocated to separate trip relays, so that any ri le trip signals allocated to Category B trip the •, 'Irle trip relay first. Then, on operation of the low "rd Power interlock relay, they trip the main trip 1 and 2. Pressure switches in the turbine fluid cia Operate the steam generator trip relays. To date, .
all CEGB power stations have used this format for their tripping systems except Dinorwig where, because of the complexity of the tripping circuits and the need to reduce the number of trip relays, diodes were used to connect trip initations to trip output relays, each one allocated a tripping function. Matrix tripping systems are being considered by the CEGB, especially where integrated generator circuit protection systems, with built in test facilities, are being offered. The matrix effectively copies the logic diagram. The trip initiations are connected to horizontal bus wiring and the output devices to the vertical buswires. The intersections of the vertical and horizontal bus. wires can be coupled by diode links represented by plugs on a matrix board. All the trip relays, or any repeating relay which is receiving signals from outside the relay room, must have a minimum operating current of 50 mA to avoid operation from induced current or capacitor discharge currents. A 10 p.F capacitor charged up to 150 V is discharged through the relay to check for non-operation on capacitor discharge currents from the negative pole of the battery.
11.3 Trip supply and circuit supervision Only trip supply supervision is provided on trip relay circuits with looping of the wiring to the positive and negative poles (Fig 11.37). Excessive looping through multicore cables is not used, thus avoiding the consequent large voltage drops in the wiring which would prevent trip relay operation. Trip circuit supervision is provided on all turbine and circuit-breaker trip coils because of the possibility of open-circuits on these coils. Figure 11.38 shows a simplified circuit. Where the trip coil and associated B relay is duplicated (which has been done on the majority of recent schemes), it is not possible to monitor both coils in the 'breaker closed' position since either circuit will maintain a trip healthy indication. However, there are two trip coils and therefore one can fail to operate. Furthermore, in the pre-open supervision, circuit-breaker fail and phases out of step protection provides additional back-up protection.
11.4 General comments on the tripping arrangements Figure 11.36 represents the basic tripping scheme as used on nuclear power stations. It is easily adapted for conventional stations with very little change in the format. All protection relays are ordered from this master tripping schematic diagram. The interfaces with the output relays on the turbine and reactor are also shown. The block for reactor tripping (Group 4) shows a full 'two from four' quadrant trip. Each of the smaller blocks Al, A2, etc., represents a 'two from three' quadrant 915
Protection
Chapter 11
BLED STEAM NON• FE RN TURBINE TRIP SOLENOIDS
BLED STEAM
ISOLATION VALVES
TuRBiNE TRIP VALVES
DISARM GOVERNOR 111.7.■+.
HP STOP VALVE & SOLENOID IF. STOP VALVE & SOLENOID HP GOVERNOR VALVE & SOLENOID IP GOVERNOR VALVE & SOLENOID
TURBINE PROTECTION WITHIN THIS BLOCK IS TyPicAL ONLY
GROUP DEFINITIONS I A DIRECT TRIP TO 51-luT DOWN THE UNIT (SEE NOTE (a)) WITH DISCONNECTION FROM THE SYSTEM BY OPENING THE Hv CIRCUIT BREAKER (PREPARES CB FAIL PROTECTION). 2 A DIRECT TRIP TO SHUT DOWN THE UNIT (SEE NOTE (a)) WITH DISCONNECTION FROM THE SYSTEM BY OPENING THE GENERATOR VOLTAGE CIRCUIT BREAKER. 3 AN INDIRECT TRIP TO SHUT DOWN THE UNIT (SEE NOTE (a)) BY TRIPPING THE TURBINE BOILER FROM LOSS OF POWER FLUID) & COMPLETING A UNIT TRIP VIA THE LOW FORWARD POWER RELAY WITH DISCONNECTION FROM THE SYSTEM BY OPENING THE HV CIRCUIT BREAKER. 4 AN INDIRECT TRIP TO SHUT DOWN THE UNIT (SEE NOTE (a)) BY TRIPPING THE TURBINE BOILER tFROm LOSS OF POWER FLUID) & COMPLETING A UNIT TRIP VIA THE LOW FORWARD POWER RELAY WITH DISCONNECTION FROM THE SYSTEM BY OPENING THE GENERATOR VOLTAGE CIRCUIT BREAKER_ 5 A TRIP TO OPERATE THE MAIN EXCITER FIELD CIRCUIT BREAKER & GENERATOR VOLTAGE CIRCUIT BREAKER WHEN THE GENERATOR HV CIRCUIT BREAKER IS OPEN & THE GENERATOR VOLTAGE CIRCUIT BREAKER IS CLOSED. 6 A TRIP TO UNIT TRANSFORMER CIRCUIT BREAKERS.
SEE NOTE c,
REACTOR GUARD LINES
7 A TRIP OF A SECTION OF HV BuSBARS WHEN THE GENERATOR HV CfFiCUIT BREAKER FAILS TO OPEN FOR A GROUP 1 TRIP, NOTES A DIRECT TRIP MEANS A TRIP OF THE TURBINE TRIP SOLENOIDS HP & IF GOVERNOR & STOP VALVES SOLENOIDS SENDING A SIGNAL TO THE REACTOR FROM LOSS OF POWER FLUID (THIS ENSURES THE TURBINE IS TRIPPED FIRST FOR ALL EXCEPT REACTOR PROTECT(ON. MAIN EXCITER FIELD CIRCUIT BREAKER & FOR GROUPS 1 & 3 UNIT TRANSFORMERS LV BREAKERS). AN INDIRECT TRIP IS A TRIP OF THE TURBINE. A SIGNAL TO THE BOILER REACTOR & A TRIP OF THE OTHER PLANT ITEMS FOLLOWING OPERATION OF THE LOW FORWARD POWER RELAY. WHERE TEN MINUTES RuN•THROUGH IS POSSIBLE, BUSBAR PROTECTION & BACK-TRIP RECEIVE.TRIP THE Hv CIRCUIT BREAKER ONLY •c) AN ADDITIONAL TRIP INTO THE STOP. GOVERNOR & TURBINE TRIP VALVES SOLENOID CIRCUITS INTERLOCKED BY CIRCUIT ISOLATORS & CIRCUIT BREAKER POSITION SWITCHES SO THAT WHEN THE GENERATOR IS ON OPEN CIRCUIT THE BOILER OR REACTOR IS NOT TRIPPED THE SIGNAL MUST BE TIME DELAYED SO THAT THE LOSS OF POWER FLUID PRESSURE SWITCHES OPERATE BEFORE THE CIRCUIT BREAKER OPENS.
TURBINE RIP BY GROUPS 1 2.3 & 4
GRID VOLTAGE KEY DIAGRAM GENERATOR TRANSFORMER
EARTHING TRANSFORMER
UNIT TRANSFORMERS
CI) iikv uNIT BOARD A
F[o.
916
11.35
MAIN 7 GENERATOR 11PVUNIT BOARD B
Overall protection logic diagram for main generating units
SEE NOTE :C1
DC tripping systems
MECHANICAL PLANT & ELECTRICAL TRIP INITIATIONS
z
SEE NOTE fa) ;
GROUP 1
2
4
5
6
7
TURBINE 2 POWER FLUID PRESSURE SWITCHES TRIP ON LOW PRESSURE LOW VACUUM TRIP
1_-.1fs f_f,fSR:CA TING OIL PRESSURE 2 CONDENSATE CONDUCTIVITY HIGH 2 LOW INLET STEAM TEMPERATURE & PRESSURE ) 2k.GF1 ONLY HIGH WATER LEVEL IN STEAM GENERATOR .:PwR ONLY) 2 OvERSPEED TRIP 2 LOCAL TURBINE TRIP LEVER 21 LOSS OF SPEED GOVERNOR REACTOR FOR NUCLEAR STATION ONLY/ TRIPS ACCORDING TO REACTOR TYPE
2 2 2 2 2 2 2
GENERATOR LOSS OF EXCITATION 1 & 2 EXCITATION FAIL TRIP (ALSO STANDBY EXCiT FAIL) STATOR EARTH FAULT INVERSE HIGH RESISTANCE 1 & 2 NEGATIVE PHASE SEQUENCE I & 2 STATOR DIFFERENTIAL 1 & 2 STATOR EARTH FAULT INSTANTANEOUS STATOR COOLANT FLOW LOW DIRECTIONAL OVERCURRENT
7-1
GENERATOR TRANSFORMER OVERALL PROTECTION BUCHHOLZ SURGE Hv OVERCURRENT 10mT 2 Hy RESTRICTED EARTH FAULT 2 HV HIGH SET OVERCuRRENT 2 OVERFLUXING 1 & 2 WINCING TEMPERATURE (-IV & LV) UNIT TRANSFORMER(S) 2 HS OVERCURRENT OVERALL PROTECTION BUCHHOLZ SURGE -I V IDMT OVERCUR RENT (2nd STAGE) 2 LV RESTRICTED EARTH FAULT 2 LV STANDBY EARTH FAULT (2nd STAGE) NV IDMT OVER CURRENT (1st STAGE) 2 LV STANDBY EARTH FAULT (1s1 STAGE) WINDING TEMP (NOT REOD ON AN TRANSFORMERS) Hi/ CONNECTIONS (POWER STATION) FIRST MAIN FEEDER PROTECTION 2 SECOND MAIN FEEDER PROTECTION FIRST INTERTRIP RECEIVE 2 SECOND INTERTRIP RECEIVE GENERATOR HV FEEDER (TRANSMISSION STN) 2 HV BUSBAR PROTECTION 2 HV BUSBAR BACK TRIP RECEIVE FIRST MAIN FEEDER PROTECTION 2 SECOND MAIN FEEDER PROTECTION
1
FIRST INTERTRIP RECEIVE 2 SECOND INTER TRIP RECEIVE 2 TRIP INITIATION HV CIRCUIT BREAKER FAIL EARTHING TRANSFORMER EARTHING TRANSFORMER BUCHHOLZ EARTH FAULT INVERSE HIGH RESISTANCE 1 & 2 2 GENERATOR VOLTAGE CIRCUIT BREAKER 2 FAIL PROTECTION
I 1
COMMON EQUIPMENT 2 EMERGENCY STOP BUTTON CCR 2 EMERGENCY STOP BUTTON LOCAL LV CONNECTIONS (POWER STATION) 2 LV CONNECTION PROTECTION 1 & 2
Flo. 11.35 (cont'd)
Overall protection logic diagram for main generating units 917
•
-
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-
Protection
Chapter 11
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7 Ton Jo. I
LIEN SW DISC3NNEcT0p
UT c. LV CIRCUIT BREAKER °
r -4— r-°-4—
I4 EEWeICIJIT
GEN MAIN EXCITER FIELD CB ▪
C HA OvERCuRRENT SEC3ND STAGE
• TJJ
TRIP SOLENOID 1
TURBINE TRIP SOLENOID 2
LAST FMFP
- 1-
SuRc.EONE PER PHA SFI
EARTHING TRANSF BUCHHOLZ SURGE .4
D -
Av-
1
re+
r
LIEN SWITCH DISCONNECTOR FAIL
—
F-C=i-°--j..- TURBINE
I
ALARM A I INDICA DON
GEN TRANSF OVERALL PROTECTION GEN TRANsrUcHHotz
-
AUTO RESET
II.
I
,) RESISTANCE
7,- ROuP •
1
. TRIP I ., RELAY
UT 0 BUCHHOLZ SURGE STATOR DIFFERENTIAL STATOR EF - NvER SE HIGH
.) —
,
MI, RELAY IA
GEN TRANSF RES7PIT'EL: ,
0-0-Auro qEsE
0
1-t
-
C NJ
E
FIELD CB TrznP RELAY B
0 SEc To
OPERATE)
•
UT O HS OVERCURRENT SECOND STAGE 0
4-11.
•-) —C:= •)—r r*,717T77:Is OC TO OPERATE)
TO TRIP CONTACTS
EARTHING TRANSF E.F INVERSE HIGH RES'S 1
0W FORWARD POWER RELAY
TI
D
Y
-
----.
lo■ TRIP RELAY
0
TRIP RELAY 3
IP R7 IP RA C-0 — r'
GROUP 21
_L9
_
oL
AUTO RESET
I
MIX RELAY
I
IF R9
TRIP RELAY 3 cry-,
ol LOW VACUUM TRIP 8 STATOR COOLANT TEMP HIGH
,
I
n19-1". TRIP 1
I
1
RELAY
TaiT I
.
ALARM 8 INDICATION
I 2_4. 4.
2IV4 1. D CB
TURBINE TRIP SOLENOID I
I -
1 0.4_
TUR BINE TRIP SOLENOID 2
1 =4,
GEN SW DSCONNECTOR
—
...GEN MAIN EXCITER FIELD CB 1-9-C)---
.. gall aNN?gEFAL r I
140
TRIP RELAY
AUTO RESET
TRIP RELAY 5
ALIX RELAY 0 — • ROL,, P
TRIP RELAY 5
LOSS OF EXCITATION I
rYI v-N
7
RV GENERATOR TRANSF WT ONE PER PHASE)
4--
------------------
I
LV GENERATOR TRANSF
▪ WT ONE PER PHASES
107M5
TRIP RELAY
TURBINE TRIP SOLENOID
TURBINE TRIP SOLENOID 2
UT S2T
0
C.-1----.
P. ALARM AND 0--1.. INDICATION
1--°-17°--1.-
FIG.
918
1-40
10SS OF ExCITATION RELAY
11.36 Overall protection schematic diagram for main generating units
DC tripping systems
rPrP RE_Ax I - itur0 .E SE
.
I
RIP RELAY AUX RELAY
7.c 1
1 RIP RELAY : -
1.E., :..ENC7 PLS. , 3L.T.7 1:1. NS
p
1 •477.1p
7,
L
'
E AX
1—n
AUTO
—()-
ALARM NOICATION
,s
iP Nir AT NO BTJE
ANE
BY "s5
.PES .5_.PE ra,c_,RE
fr
NT
L
!
J 0
Io
•oI
rem
, EACTCR QUADRANTS TRIPP,NG SYSI- EUS AI A2 El 92 ETC RELATE r000ADRANTS A 9 C AD
B ARE CZNNEC TEC 2 OUT OF ] cor,F . GuRATION al THE REACTOR ;2
C
-
0.7
op—. Al
Di
L
11.
D2 /1
GENERATOR SWITCH DISCONNECTOR
LO : SW:7CHGEAR POSITION RELAY
SW:7CHGEAR ALA SN
-0 0 . — —
7,P,TE c,, ,E Av TELEX
e- vThrTh
ME RELAY :2 secs, RELAY
I
I I
3vE RF Lu i.4x;Nzp i_ R A T, EcTION A
175---
„--,---,-,
I
-4
--_.. f. . .0--:]?. R,-FErAy _ 1 4— — —
i
r OVERFLUXING
GROUPS
PROTECTION
I
RELAY !
r_ o 1
(1) -P"-GENERATOR MAIN EXCITER I '-'-1-j... FIELD CB I C---1. GENERATOR SwITCN a j aaT r _l_... ( }jp.. OISCONNECTOR
I --1-e
l
-°
-
I
'-'47
il■
.
1.,
' C r°-L- 7 j
ALARM & INDICATION
UNIT TRANSF C LX TRIP RELAY 1
UNIT TRANSr'C' NV FIRST STAGE OVERCURSENT
--- UNIT TRANSF C WINGING 0 TEMPERATURE
4I
- - - - - - - - - - - -4 I
1 ALARM d. I no.4..0-0:i INDICATION
1 no.....L0
r
--p.
TRIP RELAY
i AUTO RESET
II. J
I
GROUP ..]<
.
FO_LO -11' UNIT TPANSF 'C' -10. IN CB
UNIT TRANSF LV TRIP RELAY I
0N11 TRANSF OHV FIRST STAGE OVERCURRENT UNIT TRANSF WINDING TEMPERATURE . I j
NOTE GROUP 7 , H1, CB FAIL! NOT SHOWN
FIG. 11.36 (cont'd)
0
ALARM & INDICATION
P. TRIP RELAY AUTO RESET
UNIT TRANSF 'Cy Ir-LVC8
Overall protection schematic diagram for main generating units
919
Protection
Chapter 11
TRIP COIL
cv-Y-Ym—s—c=
SUPERVISION RELAY
FR. 11.37 Trip supply supervision
FIG. 11.38 Trip circuit supervision
trip. For security, each of the smaller blocks Al, A2, etc., is separately cabled to the unit protection relay panel.
12 Auxiliaries systems 12.1 Operating criteria Before considering the detailed protection requirements for the auxiliaries systems, it is necessary to define the relevant operating criteria. These will generally be the same as those defined in Section 2 of this chapter for the main plant systems. It is, of course, important to maintain continuity of supply to auxiliary plant as far as possible and also the stability of the unfaulted parts of the systems. The selection and setting of protection devices for the auxiliaries systems should therefore be based upon the following major requirements: • Faults external to major power sources, i.e., unit transformers and diesel-driven generators, must only open the circuit-breakers controlling these power sources after all other protection nearer the fault has failed to clear the fault. • Faults internal to a major power source shall cause its circuit-breaker to open as fast as possible to 920
ensure that the distribution system can restore itself within the limits of stability. • The protection must be stable in transient conditions, such as motor starting, and shall not operate for current surges caused by faults external to the auxiliaries systems, which the main generator can safely withstand and which do not damage the protected plant. • The characteristics of protection equipment must match the operating characteristics of the plant it is protecting and provide discrimination with the protection of other plant connected to the auxiliary system. • All auxiliaries system faults must be cleared before the short-circuit capability of the cables, connections and switchgear supplying the faulted plant is exceeded.
12.2 Protection requirements This section deals with the protection aspects of plant and equipment connected to the 11 kV, 3.3 kV and 415 V auxiliaries systems. The various protection schemes used to cover the different protection require ments for the various kinds of auxiliary plant normally
Auxiliaries systems d in a power station are reviewed. The overall as defined above, i s to provide safe and protection to ensure that the faulted element ''' r` cn .or ec.1 as quickly as possible, thus minimising ANion to the remainder of the system. :,.. al this requirement is the need to „nownou s Wi dc protection which will be highly selective and ,,j!i[iiinaiive in its action, and that the operation of relays is ,:o-ordinated to give complete protec0 the circuits concerned and ensure that. as far : pc—ible, only faulted plant is disconnected. ,tin
Auxiliary transformers inciples adopted to protect the generator and unit pr -.,:isformers, described in Section 7 of this chapter, qually to the auxiliary transformer circuits. Due e main to the smaller ratings, there are the differences in the methods adopted when applydie protection. 12.3
123.1
Phase to phase and earth fault protection
(1•0[3 practice on auxiliary transformer circuits is not
protection were not provided, phase to phase faults would be cleared by the inverse time overcurrent relay on the HV side of the transformer and, since both these relays would 'see' the same fault current, both transformers would be tripped. With the low cost of current transformers at 11/ 3.3 kV and no restrictions on space for mounting them in the circuit-breakers, the restricted earth fault protection is fitted as a separate protection scheme. Figure 11.39 shows how the protection is applied. The high voltage restricted earth fault protection is connected in the residual circuit of the overcurrertt protection and because the HV side of the transformer is delta connected, earth fault currents do not appear in the relay coil for faults on the LV side. The relay is therefore of the instantaneous high impedance type as used on the main supply transformers and described in Section 7 of this chapter. The LV restricted earth fault protection uses the standard scheme of three CTs in the LV circuit-breaker balancing against one current transformer in the transformer neutral. This arrangement and the overall biased differential protection arrangement is shown in Fig 11.39.
;)ro% ide biased differential protection on 3.3/0.415
:ransformers, and below 10 MVA on 11/3.3 kV ormers. However, if two auxiliary 11/3.3 kV ;formers are required to operate in parallel, then -. : ,,ed differential protection is fitted to both, irreof rating: this is to avoid both transformers nping for a phase to phase fault on either trans• • aier. Referring to Fig 11.39, if biased differential ,
12.3.2 Winding faults and transformer overloads
Winding faults in all oil-filled auxiliary transformers are detected in the same fashion as for the major transformers described in Section 7.5 of this chapter. However, since all auxiliary transformers are naturally cooled, winding temperature protection gives an alarm
WHEN SPECIFIED PEOTELTICN
HV PROTECTION BIASED DIFFERENTIAL PROTECTION
7-1
AUXILIARY TRANSFORMER
RESTRICTED EARTH FAULT
3 - POLE OVERCU PRE NT RELAY
RESTRICTED EARTH FAULT
STANDBY EARTH FAULT
7 7-
FIG. 11.39 Auxiliary transformer protection
921
Protection
Chapter
only. The winding temperature device is similar to that used on oil-filled transformers and explained in Chapter 3. On the smaller oil-filled transformers (3,3/ 0.415 kV), without a conservator oil tank, the Buchholz relay is replaced by a top-oil temperature device which is set to alarm for an overload condition. This is more Cully described in Chapter 3. These 3.3/0..415 kV transformers and all air insulated transformers rely on the earth fault protection for fast clearance of winding faults. ovERcuRRENT-
12.3.3 HV inverse time and high set
PROTECT1CN RELAY
instantaneous overcurrent
The protection is applied in the same way as for the unit transformer described in Section 7.3 of this chapter and shown in Fig 11.39. The auxiliary transformer back-up protection for line to line faults on both the HV and the LV transformer connections and all plant connected to the LV side of the transformer, is provided by a relay which has an inverse characteristic, except on 3.3/0.415 kV transformers where the relay has to operate in conjunction with a 415 V fuse. In this case, an extremely inverse relay is used, since its characteristic is very si milar to that of a fuse. This gives better co-ordination between relay and fuse and is explained fully in Section 12.9 of this chapter. This relay is connected to current transformers which are located on the HV side of the transformer (Fig 11.39). The three-pole elements ensure the same clearance times for all line to line faults on the LV side of the transformer. On 3.3/0.415 kV transformers of 1 MVA and below, a switching device is used on the 3.3 kV side of the transformer circuit. This consists of a circuit-breaker and a fuse (see Chapter 5). Faults above the circuitbreaker fault interrupting capability are cleared by the fuse and the combination, as far as the protection is concerned, can be treated as a circuit-breaker, allowing the use of instantaneous relays. Figure 11.40 shows that the instantaneous relay reduces protection clearance times for cable faults, the time reduction being between 50 and 100 ms. All high set instantaneous overcurrent relays have a low transient over-reach to prevent operation due to faults on the LV side of the transformer. This is explained in Sections 7.3 and 12.9 of this chapter. 12.3.4 Standby earth fault
Back-up earth fault protection against all earth faults occurring on the LV side of the transformer is provided by a single-pole inverse time relay. This relay is operated from the neutral CT which is located in the neutral of the LV winding. The protection application is described in Section 7.4 of this chapter.
12.4 Auxiliary generators As part of the design philosophy or the maintenance 922
X X X X X 4ceA FUSE
HIGH SET NSTANTANEGUS OVERCLIRRENT PROTECrION RELAY
0 31
FIG. 11.40 Protection co-ordination for a fused switching device
of secure electrical supplies to both station and unit auxiliaries boards, it has been the practice for many years to provide additional local generation at strategic points within the power station network, so that the safe operation and control of certain essential plant can be carried out during periods of enforced disconnection from the grid system (see Chapter 1). This is achieved by connecting diesel or gas turbine driven generators directly to the 11 kV, 3.3 kV or 415 V busbars of selected auxiliary switchboards. In this context, the term 'local generation' refers to generators which are connected to these switchboards as compared with the main generator which provides generation to the national grid system. The protection scheme for local generation plant must take into account, and cater for, the mechanical failures of the prime mover. The protection scheme divides faults into those which must trip circuits and those which alarm. The distinction is made on the basis that an operator cannot he expected to correct a fault in less than five minutes from it happening. Any fault which cannot be sustained for five minutes without becoming a danger to personnel or causing serious damage must be arranged to initiate an automatic trip. The philosophy is similar to that adopted for the protection functions of the main generator unit. To illustrate the protection philosophy for local generating plant, a diesel generator system is described to show how the electrical and mechanical protection requirements of the generator set are met and how
Auxiliaries systems Ho fit into the overall protection scheme. From a point of view, the tripping functions cart ,idej into t\.vo main categories — mechanical ii
elec[rical. Mechanical trips of mechanical faults will be confined v.hich necessitate [ripping of the generator Hbreaker. The protection requirements in respect ,. pes of mechanical fault are dealt with Hi other L hapter 9. memioned previously, the essence of any prosystem is that it must be capable of detecting Abnormal condition in the equipment it is protec:2 at an early stage and of providing means of : [irlg the faulty element before any serious damage
2 41
philosophy is achieved by measuring the flow, Fhb .::lirerature and pressure of the fluids which are essen• ..11 io the healthy operation of the engine. It is normal ,J io ose lubricating oil and cooling water for this , „rpose, since their behaviour accurately reflects the ; of the engine. Hie potentially damaging situations in which prois needed, are listed below. The detection of any !hese faults results in the tripping of the circuit‘: sr{:.11.0.[r and eventually the shut down of the engine: ,
• Lubricating oil pressure low. • Lubricating oil temperature low. • Cooling water temperature high.
• Cooling water flow low. • Emline overspeed. 1. 'Ain be apparent from this list, that faults associated the fuel system supplying the diesel engine do not qui re circuit-breaker tripping. Serious consequences •ould ensue if the generator is not disconnected quickly un the electrical system when fuel supply is lost, the tripping of the circuit-breaker for failure of fuel supply system is unnecessary if a supply of ILl to the engine can be maintained for a finite period .1 time. The design of the fuel system is intended to - .th:r for this. As described in Chapter 9, the fuel oil ‘.ipply arrangements on site consist of a main tank, H. tank and a gravity tank. The main tank supplies c Jay tank, which in turn supplies the fuel to the -[::41ne via the normal fuel feed system. The gravity . .4 .111, acts as a back-up supply in the event of failure he day tank supply system for any reason. Llider normal operating conditions, fuel oil pumps .-;! hued in duplicate to feed the fuel oil to the engine ..nder pressure from the day tank. Should either or Jai of these pumps be lost, then the system transfers "lorna.tically to the gravity tank system whereby fuel gravity fed to the engine. The diesel engine will , orninue to run for several hours under this regime 1
but at a reduced generated output, typically between 20 and 45 07o of the generator full load capability. It follows that when fuel oil is available from the gravity tank, it is not necessary to provide a trip signal to the generator circuit-breaker for fuel system faults. Under these conditions, sufficient time is available for the operator to take remedial action and synchronous motor operation of the generator is neither harmful to the generator nor to the auxiliary supply system. With this fuel system design it is only necessary from a protection point of view to provide an alarm to indicate the loss of one fuel oil pump, alerting the plant operator to monitor the situation and take the appropriate action.
12.4.2 Electrical protection A typical electrical protection scheme for the generator and connected loads is shown in Fig 11.41. The protection scheme illustrated is designed to give phase and earth fault protection, using a combination of main and back-up systems to ensure that a fault on the generator circuit disconnects the generator as quickly as possible. The discrimination necessary can only be obtained by correct relay co-ordination. It is necessary to disconnect the generator rapidly in order to minimise damage, to maintain continuity of supply to other connected loads, and also to maintain a stable auxiliary supply system. The network shown is a single busbar system feeding two outgoing feeders, each of which is controlled at both ends by circuit-breakers. Any phase or earth faults occurring on the generator windings will be detected by a differential protection system, as described in Section 6.3 of this chapter. The zone of protection extends beyond the feeder side of the circuit-breakers, which means that the generator protection system also caters for phase and earth faults on the busbars as well as the circuit-breaker itself and part of the feeder circuit-breakers. The protection system is arranged to trip the generator and the two feeder circuit-breakers. The feeder protection is described in Section 12.6 of this chapter. Standby earth fault (two-stage)
Should an earth fault on the system not be cleared by any of the protection schemes described above, then the two standby earth fault protection relays fitted to the generator neutral will clear the fault. The protection scheme is described in Section 7.4 of this chapter. The first stage trips the generator circuit breaker only: if this fails to clear the fault in 0.3 s, the second stage trips the generator. Thus the protection acts as a back-up to the generator protection but is principally for the protection of the busbars, circuit-breakers and uncleared faults on the 3.3 kV system. It therefore must co-ordinate with the 3.3 kV auxiliary system protection. This is dealt with in Section 12.9 of this chapter. 923
Protection
Chapter ii DIESEL GENERATOR
2
STAGE
sTA., : m3Y EARTL. 4 FAULT 1 .Lxv
3 POLE OVERCURRENT RELAY
3 POLE CVERCURRENT RELAY
DIFFERENTIAL PROTECTION DIFFERENTIAL PROTECTION
ESSENTIAL AUXILIARIES SWITCHBOARD
FIG. 11.41
Electrical protection scheme for an auxiliary diesel generator
No reverse power relays have been fitted to guard against the generator running as an induction generator. The mechanical protection already outlined, adequately protects the diesel generator against loss of drive and the fitting of circulating current protection to the generator removes the need for fast operating reverse power protection for generator faults. The overcurrent protection of the feeder circuits provides back-up protection for uncleared generator faults, as is the case for the main generator at fossil-fired power stations. 12.4.3 Gas turbines
Gas turbines, as well as being used as prime movers for the generation of emergency electrical auxiliary supplies, are also used for grid supply system support and black start (loss of grid supply). If the last two functions are not required, diesels have the advantage of faster, more reliable starting for emergency supplies to auxiliaries. Gas turbine units are very much larger than diesel sets, sizes varying between 17.5 MW and 70 MW. The protection requirements are the same as for diesel generators, except that the gas turbines has a unit transformer directly connected to supply its auxiliaries. This modifies the protection to that shown in Fig 11.42. The electrical protection requirements of gas turbine units include both generator and unit transformer pro924
tection. A unit scheme is used to detect phase and earth faults in the machine generator windings and its connections at 11 kV. The zone of protection indicated includes the interconnecting cables between the alternator and incoming side of the 11 kV switchboard as well as between the alternator and the HV connections of the 11 kV/415 V gas turbine unit transformer. Backup overcurrent protection is provided using a voltage controlled overcurrent relay. Referring to Fig 11.43, the relay has two operating characteristics determined by the operation of the instantaneous undervoltage unit. On overloads, its characteristic matches the thermal characteristic of the generator. Under fault conditions, the undervoltage element operates, changing the characteristic to the fault characteristic and ensures positive operation on the low value of sustained fault current encountered on synchronous machines. The fault characteristic is the standard IDMT and therefore allows close grading with the overcurrent protection on the outgoing circuits of the 11 kV switchboard. The gas turbine unit has negative phase sequence protection fitted to protect the machine against uncleared faults external to the machine. It is omitted on emergency diesels in nuclear power stations in the interests of safety and continuous running during a reactor post-trip situation. A two-stage standby earth fault protection is provided as back-up protection for the uncleared earth faults in the gas-turbine generator circuit and Ii kV
Au x ka ries systems
VOLTAGE CONTROLLED OVERCURRENT RELAY
GAS TURBINE GENERATOR
2 STAGE STANDBY EARTH FALLT
BIASED DIFFERENTIAL PROTECTION
DIFFERENTIAL PROTECTION
GT UNIT TRANSFORMER 3 POLE OVERCURRENT RELAY
FIG.
11.42 Electrical protection scheme for an auxiliary gas-turbine generator
•.■ .!iarv system faults. It also acts as protection to
he eenerator for all 11 kV busbar faults. The first of the protection is designed therefore to open .• • i1 kV circuit-breaker only and, if this fails to he fault, the second stage trips the gas turbine. 1 he protection fitted to the 11/0.415 kV gas tur. :le unit trarr*ormer is the same as that described in 12.4.2 of this chapter.
• Bearing temperature high. • Rotor temperature high. • Gas inlet temperature high. • Overspeed trip. Electric generator • Outlet cooling air temperature high.
ironical trips
• Lubricating oil tank level low.
rollowing is a list of the gas turbine mechanical
• Excessive vibration. • Exciter bearing temperature high.
eenerator
• Air inlet differential pressure high.
• I aw vent temperature high.
• Lubricating oil pressure low.
• lubricatLng oil pressure low. • \ nti-icing system failure.
• Generator reading temperature high.
• [Lurie failure. • t. efl temperature high.
All the above protective devices trip the generator 11 kV circuit-breaker and shut down the gas turbine by tripping the fuel valves.
• lir intake differential pressure high. I 8
ll ■ eessive.vibration. bud inlet pressure low. Gus
pressure unbalance.
.i. cr turbine • F\cessive vibration.
• ubricating oil pressure low. • Stator temperature high.
12.5 Motors The protection scheme for a motor circuit is based on a thermal overload relay which, in addition to the thermal overload, protects against open-circuit unbalanced phases and stalling conditions. Phase to phase and phase to earth fault protection is provided, depending on whether the circuit is controlled by a circuitbreaker or a motor switching device which can interrupt the maximum fault current for the switchboard, or a 925
Protection
Chapter 11
TRIP ALARM COT
•
2 • 3
(t
-0 ()AUX UNIT
F--
VOLTAGE UNIT
NOTE ALL THREE ELEMENTS ARE THE SAME AND ONLY ONE IS SHOWN ALARM AND TRIP CIRCUITS ARE PARALLELED 30 28 26 24 22 OPERATINC, TIME s
20 18 16
-
14 12 86-
OVERLOAD CHARACTERISTIC
4-
FAULT CHARACTER/Sflc
22
4
6 8 14 10 12 CURRENT IN MULTIPLES OF PLUG SETTING
16
18
210
Time - current Characteristics al trre multiplier Setfing 1 0
Fic. 11.43 Voltage-controlled overcurrent relay
contactor with a limited fault interruption capability. At II kV, all circuits have circuit-breakers and at 3.3 kV all circuits have either circuit-breakers or motor switching devices. At 415 V, motor circuits are controlled by a fused contactor which is limited to inter926
rupting the motor starting currents; this restriction prevents the use of an instantaneous relay to provide instantaneous protection for phase to phase faults. The protection philosophy adopted by the CEGB on motor circuits is discussed in the following sections.
Auxiliaries systems Motor circuits at 415 V (contactor circuits) 12 u. • against phase to phase faults is provided : pro[c ,:tion !use. ion against phase to earth faults is also )rotcct d Lythe fuse for fuses up to 250 A. On motor . [ Je , Li 250 A or greater fuse (50 kW motors us.n ), an instantaneous earth fault relay is pro• `, ,,,,,ether with an inhibit overcurrent relay which . the earth fault relay from tripping the conor faults outside its capability. The reason for :. earth fault protection on these circuits is that ,, aft h fault loop impedance may restrict the fault to less than 1000 A, resulting in very slow .r .-. 2n t .,,,Iranee on circuits with large fuses. This results in ised damage to plant and danger to personnel. 'Th. is discussed further in Section 12.9.5 of this The protection circuit is shown in Fig 11.44. The thermal overload relays are either directly coninto the supply lines to the machine or via :-tent transformers, depending on the rating of the CEGB practice is that an overload relay can directly connected on circuits having full load curup to and including 60 A where the wiring is Where relays are mounted on hinged panels, •H.:% may be directly connected up to and including \ o nly. For circuits above these ratings, protective are current transformer operated. On electrically-held contactors, the protection relay .cmacts interrupt the AC supply to the contactor coil. He circuit is shown in Fig 11.45 (a). For latched con. : ,: tors, the protection relay contacts close to activate DC-operated trip coil. The circuit is shown in Fig 45 (b).
THERMAL OVERLOAD SINGLE PHASING PHASE UNBALENCE ETC
7
12.5.2 Motor circuits at 11 kV and 3.3 kV
The thermal overload protection on these circuits is essentially the same as that supplied on the 415 V motor circuits which use current transformers. Phase to phase and phase to earth fault protection is added in the form of instantaneous relays. It is essential to have this form of protection even on 3.3 kV motor
110v AC
CONTACT SWITCH ■ -3J
Electrically-held contactors
110V AC
PROTECTION RELAY OVERCURRENT ETC
PLANT PROTECTION
i1
EARTH FAULT RELAY
Fin. 11.44 Protection circuit for motors of 50 kW and above for contactor circuits with 250 A fuses (or greater). The earth fault element is time-delayed to allow the instantaneous overcurrent relay to operate first
,
INTERPOSING RELAY INHIBIT
EARTH FAULT INHIBIT STABILIZING RELAY RESISTANCE
CONTACTOR COIL
CONTACTOR POSITION SWITCH
OV DC
-DC
1,7PROTECTION RELAY CONTACT
OVER CURRENT RELAY INHIBIT 1250A FUSES & ABOVE
C)----
I0
TRIP RELAY 1
—
I I I I I
C=D---•
0
■1 ■ 1
CONTACTOR POSITION SWITCH
CONTACTOR TRIP COIL
(b) Latched contactors
-110V
FIG. 11.45 Protection tripping schematic for motor contactor circuits
927
Protection switching devices, as the earth fault currents are limited to 1000 A. The fuses fitted as standard in these devices are 400 A, resulting in very slow clearance on earth faults. Additionally, the switching device operated from the relay will clear the fault without blowing the fuse. This also applies on phase to phase faults to a limited extent at low fault infeeds which can be cleared by the circuit-breaker in the motor switching device arrangement. 12.5.3 Thermal overload relay
Referring to Fig 11.46, the thermal overload relay consists of three bimetal strips, one in each phase of the motor, which become heated as a result of the motor current flowing through them, causing bending or rotational movement which closes a pair of contacts to initiate a trip or alarm signal. The precise physical movement of the bimetallic strip is a function of the relay setting current. The bimetallic strips are helically wound and, when they carry the motor line current, the heat generated causes the assembly to rotate about a common axis, so that it closes the trip or alarm contact on the relay if the motor rating is exceeded. One important feature which this relay embodies is temperature compensation to accommodate for any changes in ambient temperature, so that the actuating helix will either 'wind up' or 'wind down' depending on whether there is a rise or fall in temperature. The contact arrangement is shown in Fig 11.46. The three thermal elements are mounted axially inline and are insulated from the case and from one another. The two outer elements are connected together to form one pole of the trip circuit, whilst the centre element forms the other. A radial arm on the centre element carries a lattice frame fitted with five contacts, one of which is the overload contact. Each of the arms on the outer movements carries two contacts which normally float between a pair of contacts on the centre frame and protect against phase unbalance or open-circuit. Under normal operating conditions, all three contact-carrying arms deflect through the same angle so that the two contacts on each of the two outer arms remain midway between the two pairs of contacts on the centre contact frame. The thermal characteristic required varies with the run-up time and the heating-up and cooling-down time of the motor. The thermal overload relay used by the CEGB has three characteristics of which the 20-minute type is most commonly used (Fig 11.47). This gives an operating time for motor starting currents (5 to 8 times relay rating) of 40 seconds, approximately, and suits most motors used by the CEGB on their auxiliary systems. Applying one characteristic to all motors cannot give close protection for all motors, but has proved very reliable and gives effective protection. Ideally, the relay should match closely the thermal characteristic of the motor both heating-up and 928
Chapte r cooling-down and ensure that its operation at all times stays within the safe withstand capability of the m a chine. With this kind of relay, a compromise is reached where, in some areas, the motor is overprotected. The instantaneous earth fault relay uses a stabilising resistance in series with a low impedance current operated relay. The principle adopted has already been explained in Section 6.3 of this chapter and it is cm. nected (as explained in Section 12.3.1) to the auxiliary transformers. The stabilising resistance prevents operation due to current transformer saturation caused by motor starting currents. The relay must also have a low transient overreach to allow a low setting without picking up on the first peak of the starting current. For certain applications, the provision of adequate stalling protection can sometimes be a problem. Thi s is particularly so where the safe stall time for th e motor is close to or longer than its run-up time, as in submerged cooling water pumps, or where the motor is close to its stall capability when it is operating at high load conditions. Under these circumstances, a special stalling relay is required in order to provide close relay settings between tripping time and motor stall withstand time. Referring to Fig 11.48, the current transformer/control contactor operates at values of current above three times rated relay current to switch in the thermal element. If the current falls below three times, as in a healthy motor start, the thermal unit is disconnected. In addition to the electromechanical thermal overload relays discussed, electronic relays are now being produced. The CEGB have not to date (1988) approved the use of the electronic relay, mainly because of its inability to provide fast phase to phase and phase to earth fault protection. It is proposed to use electromechanical protection, as provided in the past, in combination with an electronic relay for thermal overload protection. The advantage of the electronic relay over the electromechanical as a thermal overload device is that the relay thermal characteristic matches the mathematical thermal model of the motors more closely. Owing to modern advances in insulation technology, the quality of the insulation nowadays is such that less is required than was previously necessary for the same motor design, with a consequent reduction in frame size for the same rating. This results in a smaller heating time constant with which the electromechanical relay is unable to cope for all the requirements, and it is becoming increasingly unsuitable for close protection of motors of present day design. The requirements are: • To fit the relay 'cold' operating curve below the motor 'cold' thermal withstand curve. • To fit the relay 'hot' operating curve below the motor 'hot' thermal withstand curve. • To fit the relay 'hot' operating curve above the motor 100% volts and 80% volts starting current/ time characteristic.
Auxiliaries systems
a LOAD CONTACT
RUNNING LOAD I NDICATING POINTER
HEATER
CALIBRATING ADJUSTMENT
PRESET E LOAD POINTER
ACTIVE BIMETAL HELIX
COMPENSATING BIMETAL HELIX F1G.
11.46 Thermal overload relay
20 MIN BAND 1 000
OPERATING TIME,
10 MIN BAND
1 00
R
10
NNG ,HOTI FROM _CAD '25”, SETTING 3 2 MULTIPLES OF RATED CURRENT
4
5
6
FIG. 11.47 Motor thermal relay — 20 minute characteristic
of the above, it is clear that in order to obtain r mal protection between motor and overload I i S desirable to have a protective device which -c able to match closely the thermal characteristic c machine it is protecting. Such a device is an • .mk: protection relay which has a range of set- !i) cater for most drives which are commercially on the market. Thermal imaging is achieved •
k
-
:tronic circuits whose behaviour is determined mathematical model that describes the thermal ::enstics of the motor. The relay can be either or digital in operation, the digital relay being • •iexible. Further, quantities measured by the rebe displayed at the relay by means of a liquid •
„
crystal device, or similar. At 415 V, such sophisticated protection might not be considered necessary. However, there are essential motors connected at 415 V which are required to run following a reactor trip at a nuclear power station to maintain reactor safety, and unnecessary tripping of one of these motors by its thermal relay renders it unavailable until the relay resets to allow a motor start. Digital relays can be programmed to trip the motor, for example, on voltage disturbance, before the motor reaches a temperature which would preclude an immediate restart. Digital type protection relays, using microprocessors, therefore have very wide ranging capabilities. Most relays employing digital techniques will memorise the 929
Protection
Chapter vided by the overcurrent relay on the HV side of t h e transformer. This operates in two stages; the first stag e trips the interconnector, the second stage the transformer HV and LV circuit-breakers.
12.7 Busbar protection
SEPES PLAG ;NOICATOR
FIG.
11.48 Stalling relay schematic diagram
values of circuit parameters, e.g., load current in each phase, thermal overload capacity actually used up and also the amount remaining before reaching trip state, percentage unbalance currents, earth fault and shortcircuit currents. This information can be easily accessed at the relay to give running values of the various parameters as well as pre- and post-fault trip data. Other useful features include a pre-trip alarm and trip inhibit facility.
12.6 Cables So far, the protection requirements of motors, transformers, and generators have been discussed: these schemes usually also protect their cables which are connected to them. In these instances, faults in the cable are cleared by the main protection. Should these faults persist undetected by the main protection, the back-up protection will clear the fault, its current and type setting determining the short-circuit rating of the cable. For cables not connected to the items of plant referred to above, e.g., interconnectors, the same philosophy of main and back-up protection is adopted. The main protection is circulating current high impedance as described in Section 6.3 of this chapter. Figure 11.49 shows the 11 kV and 3.3 IcV Unit Board cable interconnector, where it can be seen that the main protection consists of a circulating current scheme. Back-up protection is provided by a combined overcurrent and earth fault relay which is located at each end of the interconnector. The relay used for this purpose consists of three elements, two used for overcurrent protection and the third for earth fault protection. At 415 V, the protection requirements are a little different, in that the circulating current protection is phase to earth only and the back-up protection is pro930
Whilst the busbar protection schemes available ar e perfectly adequate to cater for phase faults and earth faults, their use within the CEGB for power station systems has always been the subject of debate. Experience indicates that busbar faults are very i n _ frequent. The busbars are usually air insulated, which itself reduces significantly the possibility of busbar faults. This supports the view that a dedicated busbar protection scheme is unnecessary. The CEGB has not used busbar protection on any 660 MW unit power station other than Drax where, having been installed in the late 1960s on the first half, it was repeated for consistency on the second half. It has been considered for many years that to introduce a separate form of protection specifically to cover busbar faults reduces the overall reliability of the electrical system, since it complicates the protection scheme and increases the risk of malfunction. This would result in shutting down the complete switchboard, causing severe operational inconvenience and would be costly in lost production. This is particularly so for unit boards, which supply all the motors essential for the running of the main unit. At 11 kV for example, it would possibly result in the loss of a boiler feed pump, cooling water pumps, induced draught and forced draught fan motors and would inevitably result in the tripping of the main unit. The risk of losing such strategic items of plant, with the consequential loss of generation, due to the possible malfunction of a busbar protection scheme is unacceptable. For this reason, busbar protection is no longer fitted to auxiliary switchboards in this way. There is, however, still a need to guard against any faults likely to affect the busbars. The method adopted to cover for busbar faults uses the protection arrangements already discussed under transformer protection, i.e., the standby earth fault protection will operate for any busbar fault involving earth, and the back-up overcurrent protection fitted to the HV side of the transformer will operate for any busbar phase to phase faults. At 415 V, where busbar faults have been caused by human error when using multirange instruments, the back-up protection is set down to 150 ms. This can only be achieved by eliminating all forms of overcurrent protection using inverse time relays on the 415 V supply system. This method of protection at 415 V is helped considerably by the design of that system. This is explained in Section 12.9 of this chapter.
12.8 High breaking capacity (HBC) fuses The fuse has shown itself to be an extremely reliable and safe form of protection and has been used in this
Auxiliaries systems
A
Is; STAGE OF
STAGE OF oyEPfuRRENT ON 3 jk 1HANSFORMER 415v INTERCONNECTOR ONL`O p
OVERCURRENT ON 3 3kV TRANSFORMER P ROTECTION
mm TWO-STAGE OVERGURRENT AND EARTH FAULT RELAY
NOT REQUIRED ON 415V
TWO STAGE OVERCURRENT AND EARTH FAULT RELAY
DIFFERENTIAL PROTECTION RELAY
FIG. 11.49 11 kV, 3.3 kV and 415 V interconnector protection
Am, over a long period of time with great success. whilst the principal function of the high breaking ,, pae ity (NBC) fuse is to provide short-circuit procolon, it can also provide an adequate degree of ,a erload and earth fault protection for smaller circuits. It must be realised that, when considering the earth :ault protection properties of the fuse, a significant amount of earth fault current must flow before the Jo ice operates, so an adequate earth path must be provided back to the star point of the transformer. Most 415 V circuits are fuse protected and fuses are used to a significant extent for 3.3 kV circuits. CEGB practice on the use of fuses as protection and thrair co-ordination with other protection is explained he following section.
12.9 Protection co-ordination
always be maintained if a 2:1 ratio in fuse sizes is used. Experience shows this is to be so, although at very high fault currents which are operating both fuses in less than 5 ms, some grading may be lost with a 2:1 ratio. 12.9.2 Characteristics of inverse time relays
There are three types of recognised inverse time overcurrent relay and the characteristics are specified in EEC 255 4 (BS142), they are: -
• Ordinary inverse. • Very inverse.
• Extremely inverse. Typical characteristics for overcurrent relays are shown in Fig 11.51. The characteristic equation, as specified in BS142, is
12.9.1 Characteristics of 415 V fuses !fl
t
(G/Gb)a — 1
order to maintain a degree of interchangeability,
'uNes are specified which fall into the characteristic hands of 1EC 269 (BS 88). Figure 11.50 shows the characteristic bands for 10 A, 20 A, 40 A, 80 A, 160 A, -11 5 A, and 630 A fuses. The lower curve of each band :N the pre-arcing time of the fuse in the size stated and he upper curve is the total operating time of that size. \ll fuse characteristics conforming to this standard must lie within these bands. This includes the ± 10%
loltance allowed to the manufacturer on his published .haracteristic. This ensures that when replacing fuses, grading between them will always be maintained. For example, a 315 A and a 630 A fuse of any manufacturer
hich conforms to the upper and lower limit of the iLlie bands of BS88 will always grade with one another. These curves indicate that grading between fuses will
where t = theoretical operating Lime, s k = constant for that relay G= current in relay, A Gb = relay setting current, A a = index characterising the algebraic function The ratio G/Gb is therefore the plug setting multiplier. By careful choice of the values k and a, the three inverse curves at a time multiplier of unity can be produced. Suggested values of k and a for the four types of relay are given below:
a
Ordinary inverse
Very inverse
Extremely inverse
Long-time inverse
0.14
13.5 1.0
80.0 2.0
12.0 1.0
0.02
931
Protection
Chapter 11
10 000
1
1000 -
10A
20A
40A
BOA
180A
315A
630 A
100-
0.1-
10 A
50
20A
.11- 1.-
40A
100
BOA
160A , 315A
500 1000 CURRENT, A
50'00
630A
10 000
20 00 0
30 000
FIG. 11.50 415 V fuse characteristics
Since the characteristic curves are based on the time multiplier (1.0) then, when co-ordinating relays at other time multipliers, a check must be made using the actual curves specified by the manufacturer and the setting adjusted (if necessary) to obtain the required grading margin. This is particularly important when using very and extremely inverse relays, where the time of operation is not always proportional to time multiplier setting. These comments do not apply to electronic relays the characteristic values for which are shown above and for which the time multiplier is directly proportional. The setting accuracy is also to much closer tolerances ± 5 070. Relay errors must be within those quoted in BSI42. In that standard the allowable error at twice the setting is more than twice the allowable error at 20 times the setting. This does not usually affect co-ordination margins between relays, where the most critical margins more often than not occur at the higher current multiples. It can affect the grading between a fuse and a relay. 12.9.3 Characteristics of definite time relays
The characteristic of a definite time relay with 2, 4 932
and 8 s settings is shown in Fig 11.51. The operating ti me is independent of the current input which means that the grading interval can be reduced as CT errors do not have to be included. This is offset to some extent by the fact that the allowable relay errors are ±10o instead of ±7.5 070. From a practical point of view, the inverse and the definite time relays could be treated in the same way as far as grading margins are concerned. Section 12.9.6 of this chapter gives the equation for the grading interval. In order to simplify the grading process, the CEGB co-ordinates the system using inverse time relays and reserves the application of definite ti me relays to specific cases, as follows: (a) For fast clearance over a wide range of fault levels. When grading with a fuse this can sometimes be better achieved using a definite time relay than with an extremely inverse time relay. At the lower plug setting and time multiplier setting of the extremely inverse relay, co-ordination between fuse and relay is lost at the lower fault levels. Faults between phases generally produce higher fault current than for earth faults at 415 V, where the earth fault
C)PLI-tAl 11,6 Irr
Auxiliaries systems
LONGTIME STANDBY EARTH FAULT N , 20 IV
STANDARD INVERSE t.0 14 ,
follow the thermal capability of the protected plant and, in particular, of induction motors (see typical characteristics on Fig 11.47 and compare with those on Fig 11.51). They have longer operating times than the inverse relays. The relay has other protection functions such as stall, single phasing, negative phase sequence and earth fault protection. It is only necessary for co-ordination purposes to know the characteristics of the instantaneous and thermal relay and, if working in conjunction with a fuse, the fuse characteristic. The process will be explained later to show how the combined characteristic made up of a fuse, an instantaneous relay and a thermal relay reduces clearance times of back-up protection further up the system and, in the case of large motors connected at 11 kV, determines whether differential protection is required. 12.9.5 Calculations
The data required for a co-ordination study are: • A single line diagram of the supply network, as shown in Fig 11.52. VERY INVERSE 1=13 5 .11.11
INVERSE EXTREMELY ,
t=so iz
IC
CURRENT IN MULTIPLES OF SETTING
FIG. 11.51 Characteristics of an overcurrent relay with
various time settings
loop impedance can be high. It can also be used successfully where it is difficult to clear low level earth faults on interconnector circuits and busbars. At 415 V, it would be grading with a fuse, so that its current setting must be high enough to co-ordinate with the largest fuse on the outgoing circuits. (b) They are ideal for use throughout the supply system as back-up protection, such as on radial feeders at the same voltage level. Radial feeders are rarely used on CEGB auxiliary systems other than 415 V where fuses are the only protection. (c) Where above a fixed current setting, operation is required in a definite time. They cannot provide close grading with a mixture of fuses and inverse relays unless the definite time relay is the first relay in the grading chain. An inverse relay will always grade much closer to another inverse relay than a definite time relay. It is practice in modern relays to incorporate both inverse time and definite time characteristics in one relay. 12.9.4 Characteristics of thermal relays
The characteristics of thermal relays are designed to
• The impedances of all power transformers, rotating machines and feeder circuits. The impedances are first converted to the per unit (p.u.) value by using p.u. value = actual value/base value, where the base value chosen depends on the actual value. If actual value is: (a) Volts The base value is the nominal phase to neutral voltage of the relaying point.
(b) Amps The base value is preferably the full load current of the circuit protected. This is not essential but is a convenient value to choose. (c) Ohms The base value in ohms is then (a) divided by (b). The per unit system can be completely defined by specifying (a) and root 3 times the product of (a) and (b), i.e., a base MVA value. If the base value in ohms is required, it is given by: (phase to phase voltage in kV) 2 /MVA base Note: Any two base quantities will fix the third but (a) must be one of them. The maximum and minimum values of short-circuit current that are expected to flow through the relay during normal and transient conditions are next calculated. Generally, when considering the settings of overcurrent relays, the minimum short-circuit is not required since the current setting is dependent on the maximum continuous loading of the circuit, the relay resetting current ratio and the primary current setting of the relays in front. The recommendation is to use a factor of 1.3 times the largest of these three values. However, for the instantaneous relays, as with unit protection relays, it is important to check that at the minimum fault level the current is at least twice the 933
Protection
Chapter 11
400k V
GENERATOR TRANSFORMER
560 MW GENERA TOR UNIT TRANSFORMER 60 MVA 18.6% IMPEDANCE
1
x 750 MVA
1 kV
I 1.3 3kv AUXILIARY TRANSFORMER 10 MVA 8% IMPEDANCE
3.3kv
250 MVA
250 MVA
33415V AUXILIARY TRANSFORMER 1.6 MVA 6% IMPEDANCE 1 500kW 415V r' 630A 0
0
100 kW
FIG. 11.52 Network single line diagram The network shows a main (660 MW) generator supplying an 11 kV busbar through its unit transformer. The supply to the 3.3 kV and 415 V busbars are by unit auxiliary transformers 11/3.3 kV and 3.3/0.415 kV respectively. For the sake of clarity, representative motors have been shown at 3.3 kV and 415 V only. The 11/3.3 kV systems each have bus-section circuit-breakers and each section is supplied by an alternative transformer. However, to demonstrate the co-ordination of the relays it is not necessary to include these alternative supplies.
setting current and the current transformer knee-point is not reached before twice the relay setting current. This will ensure positive operation of the instantaneous relay. This can be checked simply by the following method: (i) Calculate the relay circuit impedance at twice the setting. This is the sum of the relay, plus the leads, plus the CT, plus any other relays in the circuit. (ii) Either from the accuracy limit factor or from the CT magnetising characteristic, derive the CT knee point voltage. The accuracy limit factor is defined as the primary current up to which the trans934
former maintains its accuracy within its prescribed limits of error, expressed as a multiple of its rate current. (iii) Divide (ii) by (i), giving the knee-point voltage: this should be greater than twice the setting. Suppose the current transformer is 10 VA with an accuracy limit factor of 15 and a rated secondary current of 1 A. Then, if the secondary burden is 1 11, the current transformer can deliver 15 x 10 volts (knee point voltage) into 111 which is 150 A. A setting of 75 times is therefore possible. Fifteen to 20 times is more likely to be the required setting on high set instantaneous relays.
Auxiliaries systems In calculations to determine the maximum operating f au lt levels, a simple calculation based on the system impe dance which is the equivalent to the switchgear catinq is recommended for the following reasons. Calculations based on incoming transformer circuit impedances alone could result in an underestimate of m e peak current for which the instantaneous relay is CO remain stable. This is not so important for :e qUired rading beteen inverse time relays by themselves rne g he contributions from induction motors, which cont titute the switchgear making requirement, are of a s -ansient nature (10 cycles) and have no effect on the ,i or adina between them. However, if the protection at he relaying point contains high set overcurrent relays, for example, on transformer circuits, the first few cycles of an offset current waveform may cause unwanted operation of the instantaneous relay under throughfault conditions if an underestimate of the fault current has been made, An example of the calculation is given in Sections 12,9,6 and 12.9.8 of this chapter, neglecting induction motor infeeds. A decrement curve needs to be calculated from generator data or obtained from the manufacturers of the generator, for systems where he predominating infeed is from local generation. The protection may be required to operate when the generator is disconnected from the system, in which case t he grading of the system worked out for connection to the supply network will have to be rechecked. The procedure is to establish relay settings for all conditions when running in parallel with the supply network and then examine the relay performance when supplied from local generation only. It may not always be possible to grade the protection adequately for both situations and thought has to be given to splitting the network, when operating on local generation, in such a way that continuity of supply can be maintained for faults on the network. Current transformer performance curves should be checked for output at the grading point determined by the maximum fault level or at the setting of the high set overcurrent if there is one. It is important for overcurrent relays that the current transformer does not saturate at maximum fault level, as the operating time would be increased and then may not co-ordinate with the backing relay driven from current transformers that do not saturate. 12.9.6 Discrimination Discrimination is required for both current and time.
Current grading For relays which carry the same p.u. current under fault or load conditions, it is essential that they do not op-
erate in the same time. At the maximum fault current, this is avoided by adjusting the time of operation. At the minimum fault or load current, inverse time relays with the same setting could operate in the same time due to the nature of the characteristic, irrespective of
the time setting. This is mainly due to the fact that below twice the current setting, the relay characteristic tends to be asymptotic to the time axis; it is therefore indeterminate and certainly not accurate enough to ensure grading. In addition to this, the errors are more than twice those at the higher fault levels. Practical experience shows that with the backing relay set at least 1.3 times the one nearest the fault, grading is assured. Grading between fuse and relay must be at least three times and this may be insufficient if a low ti me multiplier is chosen. Only a plot of both fuse and relay characteristic will confirm this.
Time grading — relay to relay The grading point is determined at the intersection characteristic of the high set instantaneous relay setting and the inverse time relay (point X, Fig 11.53) or point Y, the maximum fault level, if the protection does not include a high set. The grading interval (At + B) between protective devices is made up of a fixed interval (B) and one depending on the operating time of the relay in front (At). The fixed interval B is made up of two components; the first is the fault current interrupting time of the circuit-breaker. The operating time of the circuitbreaker includes the time from trip coil energisation to arc extinction. Usually 100 ms is allowed for this, giving a margin of safety as the actual time is normally 70 to 80 ms. The second component is the overshoot time of the relay. When the relay is de-energised, operation may continue for a little longer until all the stored energy is dissipated, e.g., disc type relays have energy stored in the disc, solid state relays have energy stored in capacitors. The overshoot time is defined as the difference between the operating time of the relay at a specified value of the input current and the maximum duration of this current which, if suddenly reduced to a current which will not cause relay operation, is then insufficient to cause operation due to overshoot. In other words, if two relays are operating to a trip condition, the following relay with the longer time setting must not continue to the tripping point due to its inertia. The time allowed for the overshoot is 50 ms and must not exceed 100 ms (Fig 11.54). If a margin of safety is allowed, a reasonable fixed grading margin (B) is 250 ms to include both components. The time coefficient A depends on several factors. All measuring devices such as relays and current transformers are subject to some degree of error. The operating time characteristic of either or both relays involved in the grading may have a positive or negative error, as may the current transformer. The errors are taken in accordance with BS142, which calls for a relay error class of E7.5, i.e., 7.5% at twenty times setting. It could be that one relay is slow and the other relay is fast so that 15% must be allowed. Allowing 10% for
current transformer errors, the total error at any time 935
Protection
Chapter 11
•■•■•■•■■1■••■....
I 'KV BUS SECTION
SYSTEM GRADING
4013k V
IDMT 57 16 MVA
TmS.0 175
GENERATOR TRANSFORMER
BUS SECTION 3 3kv 10MT 1. 1 43 MVA "MS=0 125
111
r
GENERATOR
3M VA TRANSFORMER IOMT 17
1
1 , kV
5KWA
TmS=0 2
'
3 3kV 400A I.
I 5 MVA TRANSFORMER XPOMT
2 04 MVA TMS=0 45
60 MVA UNIT TRANSFORMER 10MT 75 32 MVA THS-0 25
4
'
4U"
4150 6304
5
HIGH SET OVERCURRENT 484 MVA NIGH SET OVERCURRENT1187 9 MVA
01-
\
NIGH SET OVERCURRENT 36.14 KIVA
3.01 10
100
1000
CURRENT MVA
FIG. 11.53
Network protection grading diagram
will be 0.25t, where t is the operating time of .the relay in front. This does not apply to current independent relays, since they are independent of current transformer errors. The total grading interval is (0.25t + 0.25). The resulting ti me of operation of the next relay for I DMT relays is the operating time of the relay in front (t) plus the grading interval (At + B), giving t + (At + B) = (1.25)t + 0.25; and between definite time relays, which are independent of current transformer errors above their setting and meeting class EIO (i.e., A 0.2), giving t + 0.2t + 0.25 = (1.2)t + 0.25.
section on current grading that at low time multiplier setting, the fuse and relay may not grade at the low fault level. This is shown in Fig 11.55 region 'X', where relay 2 (a) meets the requirement at the higher fault levels but crosses the fuse characteristic at the lower fault level. This is easily checked by plotting the grading curves. The crossing of the fuse curve at the low fault level can sometimes be allowed on the basis that phase to phase faults at a low level are unusual and, by the nature of the transformer phasor relationship, grading is achieved for earth faults. To achieve fast operating times and good co-ordination a relay with an extremely inverse characteristic should be used.
Time grading — relay to fuse As far as the practice of grading inverse time relays
Transient overreach
with fuses is concerned, providing that the relay is not
For a given RMS value of operating current, a relay will usually operate at a lower value due to the offset of the initial peaks of fault current. The degree of offset
closer in time than 150 ms at the maximum fault level,
the time grading is achieved. It was mentioned in the 936
"NrIP"Auxiliaries systems
- RELAY OPERATING CHARACTERISTIC
former. Whilst operation for faults on the LV side of the transformer circuit is desirable, the relay cannot distinguish between these and faults on the outgoing circuits from the 3.3 kV switchboard. To calculate the setting for the high set instantaneous relay, proceed as follows. Referring to Fig 11.56 (b), we know that the RMS value of l A c, expressed in MVA, is 107.1 N1VA. We need to calculate the value of the DC component and hence the peak current. = time, s T [DC
RELAY CURRENT lop
PG. 11.54
[
2
Relay overshoot
Overshoot = 4.1 - t7: where t2 = relay operating time at l op ti me when switching from l op to I the relay just does not operate = 85 177o of relay setting current (usually)
,1/4,11 Jepend on the X/R ratio of the fault circuit and point-on-wave at which the fault occurs. This facor can lead to relays operating for faults outside -le intended protective zone and is called transient
erreach. The definition of transient overreach is the differ, , Le between the RMS value of the steady state curv,hich when steadily increased will operate the relay and the RMS value of current which, when fully r et by point-on-wave switching, will just operate the Hay (f op ) expressed as a percentage of I cp (see Fig 1.56 (a)), i.e., (Is - Iop)/Top X 100%. If, for exam-. e, f s = 2 A and l op = 2/1.05 A, the overreach .;ualS 5 6'0 and a setting of 2.1 A on the relay would 7.2%ent operation for currents less than 2 A. This is et a practical setting as no allowance has been made .,1r errors in relays, current transformers and inrush ...rrents on transformers and motor circuits, the CEGB , ouId therefore use a minimum setting of 1.5 x 2 = .
Consider an instantaneous relay on the HV side of 'le 10 MVA 11/3.3 kV transformer (Fig 11.52) with fault current through it as shown on Fig 11.56 (b). Ple 10 MVA transformer has an 8% reactance. As-Arne the 11 kV busbar fault level is 750 MVA which, •\Pressed as a per unit impedance, is Z = 10/750 = . 01333. So, the fault level on the 3.3 kV side is 10/(0.08 + 1333 ) = 107.1 MVA. The AC component of the irrent waveform, expressed in MVA is 107.1 MVA. IS required to find the magnitude of the first peak hat the relay setting can be determined which will .01 operate for faults on the LV side of the trans-
= circuit time constant, s l Ac exp( - t/T)
The reactance to the fault is 0.08 + 0.01333 = 0.09333 p.u., assuming that R is 0.00667 p.u., making X/R = 14 (tan - 1(14) = 86 ° ). For 50 Hz, w = 314. Therefore T= X/Rw = 14/314 = 0.0446. The first peak occurs at (t = 0.01 s), exp( t/T) = exp( - 0.01/0.0446) = 0.799 Therefore IDC = 'AC X 0.799 and NC The formula for the envelope AA" is ' MC= 'AC x (1 + exp -t/T)
lAc
rAC
'DC
x (1.799)
Using this formula, !AC = \12 x 1.799 x 107.1 = 2.55 x 107.1 = 273.1 MVA. So, on this system to avoid the first peak of 273.1 MVA, a relay responding to the peak currents would need to be set above 273.1 MVA, preferably at (2.9 x 107.1) = 310.6 MVA, whereas using a relay with a transient overreach of 5% at an angle between the fault current and system voltage greater than 86 ° , a factor of 1.5 would allow for errors and magnetising inrush currents. On relays with overreach quoted at angles less than 86 ° , a factor of 2 should be used if the system fault angle exceeds 86 ° . The settings for the three types of relay to ensure grading would be: • No quoted overreach
310.6 MVA.
• 5% to 10% overreach >86 ° 160.6 MVA. ° • 5% to 10% overreach >86 214.2 MVA. ° Modern electronic relays will give 5% at 84 and 10% at 88 ° . This brings in the need to use relays with low transient overreach, so that a setting as close as possible to the through-fault setting of 107.1 MVA can be achieved.
937
Protection
Chapter 11
00'
'Co CURRENT MVA
Fin. 11.55 Protection grading for phase fault relay-to-fuse, demonstrating non-grading at low fault levels. 12.9.7 Techniques to obtain close co-ordination between protection stages Fuse to fuse
Section 12.9.1 recommends that the choice of fuses
should be restricted to the characteristic bands of IEC 269 (BS88). The pre-arcing and total operating time characteristic plus tolerance (± 10%) must lie inside the characteristic band of IEC 269 (BS88). I f the circuit is a motor circuit, providing that the pre-arcing characteristic of the fuse selected does not lie outside the lower band of BS88, the same current rated fuses of different manufacture can be interchanged without losing co-ordination through ageing of the fuse. Fuse ageing is caused by frequent operation into the fuse pre-arcing time and will cause operation of the fuse at lower current values than specified. This can incur delays whilst the cause of the fuse blowing is being investigated or even loss of production if the motor is being brought on in an emergency. 938
As an alternative to using the BS88 bandwidths for grading, it is possible to use the manufacturer's published data for a particular fuse. This generally gives a much narrower operating bandwidth and a possible reduction in the 2:1 principle for discrimination, thus achieving closer grading, faster fault clearance times and smaller fuse sizes in the fuse switch on a motor circuit, with consequent better protection. If this course is adopted, the user must ensure that only fuses from the same manufacturer and of the same type are used for replacements. To do otherwise would invalidate the overall discrimination. Taking into account the long lifetime of the equipment being protected, the continued availability of a particular fuse is not guaranteed. Also there is a real possibility that the user unwittingly replaces a fuse with a different make without first checking its characteristic, with a possible risk of losing discrimination. Using IEC 269 (BS88) as the basis avoids this risk, i.e., only fuses (including tolerances) complying with IEC 269 (BS88) are ordered and used as replacements.
Auxiliaries systems 650 V is 0.2 s, then (650/430) 2 >< 0.2 = 0.46 s, is the back-up clearance time allowed, Fuse to relay
11ME
•„
1
FIG. 11.56
.
Transient overreach
Part of the assessment of the protection system %olves estimating the likely fault clearance times to .::,ure that the plant is correctly rated (cables, switchetc.) and that no danger exists for personnel who ht be in close proximity to the faulted plant. Genthe phase to phase faults are not limiting factors these are generally high enough to cause rapid clear.r.,;c of the fault by the fuse. However, phase to ...ifth faults, even direct to the sheath, can be long in :caring if the cable to the protected plant is very long. ( EGB practice is that if the sheath is only earthed at sending end, then to prevent a dangerous conarising at the far end of the cable, the protection icarance time for an earth fault condition should not 'e more than 0.46 seconds. This time is based on the :drth potential rise and duration following faults on • 'le power station auxiliary system. A voltage of 650 V for 0.2 s has been internationally . , ablished and is based on experience of the I 2 R withand of of a human being. Where R is the resistance of numan being and I the current flowing through the • )(4. For back-up protection clearance times, the (EGB adopts a figure, based again on international :ndin gs , of 430 V. Therefore if the time allowed at -
At low voltage (4 t5 V), a relay with an extremely inverse characteristic should always be used if grading with a fuse, as the relay characteristic follows that of the fuse very closely. If the relaying point is on the NV side of the transformer, then a three-pole overcurrent relay is always used to ensure that one phase of the relay carries the equivalent of a three-phase fault current, irrespective of whether the fault, if on the LV side, involves two or three phases. The relay will then always operate in three-phase fault current operating time for all phase to phase faults on the LV side of the transformer. When co-ordinating the fuse and the relay, the grading interval has to be maintained when the fuse is carrying phase to phase fault current and the relay is carrying the equivalent three-phase fault current, i.e., 2/., 3 ti mes the fuse current. The exercise in the next Section 12.9.8, will show that no adjustments are necessary to allow for the difference in operating currents due to the rounding upwards of the current and time multiplier settings (TMS) to obtain a practical relay setting. If the relay grading with the fuse is for earth fault protection and the relaying point is at 415 V, the current setting range must be made high enough. For instance, a setting range of 10-40% on an earth fault relay will not allow grading with a 200 A fuse since a setting of at least 75 070 is required. The grading of the earth fault relay with a 630 A fuse requires a setting of at least 100 070, or preferably 120%. This is illustrated in Fig 11.57. A higher current setting on the phase fault relay at a lower time multiplier will give faster operation at the higher fault levels. Considering Fig 11.58, the relay can be set at 120% TMS 0.45 or 150% TMS 0.2. The reason that the 120% setting requires a 0.45 TMS and not 0.275 as would be required for grading at the highest fault level, is that grading is not being achieved at the lower fault level and this can be seen by reference back to Fig 11.55, where it is demonstrated that relay 2 would not grade at point X. With the 150 070 and 200% settings, the grading is determined by the minimum operating time of the relay. In Section 12.9.1 of this chapter, it is stated that closer grading can be obtained if the combined characteristics of the thermal relay and the fuse are taken into account. At 415 V, this will rarely occur, since the majority of the circuits are controlled by contactors and the main protection is the fuse in the fuse switch. At 3.3 kV, fuses and switches are co-ordinated to give a full fault clearance capability, allowing the use of instantaneous relays. This means that the circuitbreaker handles faults up to 50 MVA but above this level the fuse operates. The co-ordination is by time. The operating time of the circuit-breaker and protec939
Protection
Chapter 11
-
10
CURRENT. MVA
FIG. 11.57 Grading of earth fault relays
tion (80 ms) at this fault level is always longer than the fuse operating time (65 ms), see Fig 11.58. it may also mean that, with one transformer supplying the board, which is normal, the circuit-breaker could clear the fault due to the limited fault infeed and only when two transformers are paralleled will the fuse be required to interrupt the fault. With this combination, the relay on the bus-section circuit only needs to grade with the point of intersection of the thermal relay and high set instantaneous relay at the lower fault level, and not the fuse. This is explained as follows. Figure 11.55 shows the three characteristics, consisting of a thermal relay with a high set instantaneous relay on a 1 MVA motor at 3.3 kV and a 400 A fuse combination. The shaded portion is the operating area. The 3.3 kV bus-section overcurrent relay has to be set at 150% to grade with the high set on the motor and the overcurrent relay on the incoming 5 MVA trans940
former has to be set to 200% to grade with the 3.3 kV bus-section relay. if the bus-section relay (3) was grading with the fuse, its plug setting would have to be about 250% and relay (4) 325 07o. Figure 11.58 shows relay (3) set at 150% and relay (4) at 200 07o. This is the maximum size of motor (1500 kW) that the protection can grade without using a very high setting on the incoming transformer overcurrent. The alternative may be to use differential protection on the motor to get a lower setting if the overcurrent relay on an outgoing 3.3/0.415 kV transformer is not the limiting factor for relay (3) (as it is in this instance, i.e., relay (3) cannot get closer to relay (2)). 415 V motor protection
Motors at 415 V are commonly switched by a contactor and protected by a combination of a thermal relay and
Auxiliaries systems
I0
1 00 CLIIIIRENT.MVA
FIG. 11.58 Protection grading for phase fault relay-to-fuse, demonstrating faster operation at high fault levels.
.. fuse. Larger motors, requiring relatively large fuses +.n excess of 200 A) need extra protection against earth ' Ats, since the fuse cannot safely cope with low values or earth fault current. For an example of an application additional protection to contactor circuits, consider he 630 A fuse on the 100 kW motor. A contactor is equired which will meet the following requirements ontinuous rating of 200 A (20% overload on full load .urrent of 162 A), and has a capability to meet the cutoff current of the 630 A fuse at 24.09 MVA (see Table [1 .1). Assume the duty required of the contactor is to \C3 duty in BS5424. This means a breaking current of ix times the AC3 duty of the contactor quoted by the manufacturer. A typical figure could be 190 A for a 200 ontactor, giving a figure of 1140 A. Referring to Fig 11 9 .) , it can be seen that the earth fault relay would • ave to be delayed in excess of 100 seconds even if the :use characteristic lay close to the minimum pre-arcing .me of the fuse to ensure the contactor is not called Pon to clear a fault above its rating. The solution is ,
:
,
to provide a definite time earth fault relay with a fast operating time (300 ms) and prevent its operation above the contactor rating (see Fig 11.59) by means of an instantaneous relay. Ideally, the fuse should clear all faults above the contactor rating and the protection should initiate opening of the contactor for faults within its rating. The fuse, however, is selected for its ability to withstand the motor starting current peaks and consequently fault clearance by the fuse may be slow not to correspond to the motor full load current for some faults above the contactor rating. For phase to phase faults, fuse protection is usually adequate and the addition of the earth fault relay covers for earth faults. A range of special motor circuit fuselinks are available which are physically smaller than the standard general purpose fuselink. These fuselinks are given a dual rating, e.g., 200M315. A fuselink with this designation is rated to operate at 200 A continuously but has a time current characteristic for short-circuits that falls within the standardised zone for a 315 A fuse. 941
Protection
Chapter 11 TABLE 11.1 Plant protection data
Maximum fault current MVA
Device type
CT ratio
CT primary current MVA
250
300/1
1.71
2000/1
I1.43
(1)
415 V ruse 630, A
(2)
XIDMT 3 3 kV/415 V, 1.6 N1VA
(I)
XIDNIT 3.3 kV bus-section
125
(4)
1 DNIT 11/3.3 kV 10 MVA
750
600/1
11.43
(5)
I DNIT 11 kV bus-section
321
3000/1
57.16
(6)
I DNIT 23.5/11 kV, 60 MVA
8000
1500/1
61,05
High set relay current MVA
Rela y setting MVA
24.09 36.14
2.06 11.43
187.9
17.14
57,16 484
78.32
10000
1000
-
100 -
INSTANTANEOUS EARTH FAULT PROTECTION + 100rns TIME DELAY
SETTING OF INSTANTANEOUS... OVERCURRENT
INHIBIT TOTAL FAULT
CLEARANCE TIME FOR EARTH FAULT 01
CONTACTOR OPERATING TIME t
0o1
10
1000
100
10000
1 00000
CURRENT A ---- COMPOSITE PROTECTION CURVE USED FOR GRADING
Ho. 11.59 415 V motor circuit protection co-ordination
Use of these fuses therefore requires less space for the fuses in a starter for a given motor size, or a given fuse accommodation will allow a larger motor to be operated. However, the latter mode of operation could permit a cut-off current and energy let-through in excess of the proven and certified rating of the equipment concerned. This aspect must be considered and satisfied for every application of motor circuit fuselinks, preferably at the design stage. 12.9.8 Application to a typical system
From the system diagram, a path is chosen that gives the highest settings for current grading. A typical path 942
is shown in Fig 11.52; from the largest fuse at 415 V through the section switch at 3.3 kV, onto the I I kV busbar via the largest transformer, onto the 3.3 kV busbar and then through the bus-section switches at 11 kV. This ensures that all the bus-section switches are set to grade with any outgoing circuit and all the incoming transformers will grade with the section switches. Since the grading depends on the largest fuse it is essential to allocate fuses to circuits. Non-motor circuits must ensure that the fuse will protect the cable. This means that the fuse must have a rating above the cable continuous rating but that a fault on the cable must be cleared before the whole cable receives
Reliability „nano( damage. Phase to phase faults are cleared by the fuse so are not a limitation. Phase however, could be low and may take fau lts, j lorig. time io clear. The cable size and length , to the sheath at the that .1 ,hort-circuit pf the .;ible is cleared by the fuse in less ee previous section); this ensures that 0.46 do not occur on the cable hc
•
circuits, the fuse selection is more
niu t The following must be considered: •
capability of a fuse must withstand two f- },2 [herrnal motor starts without any potential deter• ,•,•,[1,,ceutive in subsequent performance. ,,r,ition
full load current, as determined from the
foior and power factors recommended •1%erage efficiencies 3 of IECTC2. ri Table
•
Nominal motor starting currents, as calculated from , kW ratio/1.73 kV, using the ratio of starting kW derived from Table 41 of BS4999, \.• to output
•
r.irt 4 1 .
• k‘erae motor run-up time, as determined from Aupirical formula 3 + kW/7.46 in Table 1 of BS587 :or times up to 5 s and rounded up to nearest 10 s imurn for times greater than 5 s. • the permissible deviations of not more than 10% in terms of current from fuse manufacturers published Lurves, as allowed in BS88 Part 2 1975. • the fuse characteristic curve bandwidths, as defined iii
BS88 1975.
I or example, consider the 100 kW motor on the system Full load current Nominal start (BS4999 ratio) Starting current Starting time 3 + kW/7.46 Assuming two starts
162 A 780 kVA 1085 A 10 s 20 s
I Qmination of Fig 11.50 gives a fuse size of 630 A .
,
The following steps are taken to determine settings or he relays (current and time multipliers) to obtain o-ordination between the relays and the (relays +
Table 11.2 must now be drawn up for all the relays the fuses on the path must be chosen, determining he high set instantaneous relay settings as described in he previous section. The procedure is as follows: • Column 1 is self-explanatory. -I P. d
• Column 2 is determined from Section 12.9.6 of this chapter, e.g., for the 1.6 MVA transformer, the highest setting current is 1.3 )( full load current of he transformer, i.e., 2.08 MVA. Therefore, 125% (2.06) the nearest relay tap setting, is suitable for this relay.
• Columns 3 and 4 also derive from Section 12.9.6; column 3 is the nearest high set overcurrent relay setting or, if there is no relay, the maximum fault current through the IDNIT relay. For example, the fuse grading current and cut-off MVA is the maximum fault MVA, from Table 11.2, i.e., 24.09 MVA. • Column 5 is the current setting multiple at the grading point. For example, grading the bus-section with the 1.6 MVA transformer, the grading current ( MVA) (column 4) is the setting of the high set on the 1.6 MVA transformer (36.14 MVA). This is 17.72 ti mes the 1.6 MVA transformer relay setting and 3.17 times the setting of the bus-section relay. • Column 6 is derived directly from column 5, using the characteristic curve for an extremely inverse relay with a time setting multiplier of 0.45, already determined when grading it with the fuse. • Column 7 uses the grading equation, i.e., 1.25 x 0.17 = 0.46s. • Column 8 is obtained by using the value for Relay 2 in column 5 and the characteristic curves for an inverse time relay to obtain the time in column 7. Completed results are shown in Table 11.2 with additional explanations to derive the values in the columns. All grading points have been checked for phase to phase faults. No alterations in settings had to be carried out since the nearest time multiplier and current
setting multiplier in an increased direction had been selected. Figure 11.53 and Table 11.3 give the computer grading curves. If the time multipliers are rounded up to the nearest step, 0.025, the pick-up and time setting multiplier figures compare exactly with columns 2 and 8 in Table 11.2.
13 Reliability In order that protection equipment can operate efficiently and without interruption throughout life, it is essential that it must possess the highest possible
reliability and availability. In this context, it should be remembered that protection is normally quiescent but must operate reliably 'first time'. It is vital, not only that the equipment is installed and operated in the prescribed manner and in the right service conditions, but also that it receives regular attention in line with manufacturer's recommendations. Records of relay unreliability show that the majority of failures are attributable to bad connections between components by way of dry solder joints, broken conductors, defective connector contacts and faulty wiring, etc. It is acknowledged that it is virtually impossible to avoid all hardware failures in a protection system, but the probability of such events happening is reduced by careful design and by the adoption of good quality assurance procedures by the 943
414 TABL1 11.2 Determination of system protection settings Column (see notes)
1
2
3
4
Stage and device type
Relay type
MVA selling
Relay cut-off, MVA
Fault MVA for grading
5
6
7
8
Current setting multiple at grading point
Operating ti me relay in front, s
Operating ti me relay to be graded, s
Time mull iplier setting
(Relay 1)
(Relay 2)
("1' MS)
Relay l 24.09
(1) 415 V fuse 630 A (2) (3) (4) (5) (6)
Relay 2
1.6 MVA transformer Bus-section, 3.3 kV 10 MVA transformer, 11/3.3 kV Bus-section, 11 kV 60 MVA transformer, 23.5/11 kV
XIDMT 1 DMT 1 DMT 1 0MT 1 DMT
2,04(120%) 11.43(100%) 17.15(150%) 57.16(100%) 76.32(125%)
36.14
24.09 17.72
125.00 187.90
36.14 125.00
323.00 484.00
187.90
10.94 10.96
323.0
5.65
11.81
0.23
0.45
3.17 7.29
0.46 0.66 0.94
0.125 0.200 0.175
1.13
0.250
0.17 0.33 0.54 0.70
3.29 4.23
Notes: • Column 4: equals column 3 value for previous stage • Column 5, Relay I: equals column 2 value for previous stage • Column 6: from the relay curves, read off the time from the nearest curve with settings given in column 5. Then calculate the time front Actual TMS/Curve TMS x (time from selected curve). If TMS = 0.125 take curve for 0.2 and time at 0.125 = 0A25/0.2 x (time at 0.2) • Column 8: is column 7 divided by the operating time of Relay 2 with CSM (column 5) at nearest TMS to give column 7 time x TMS for selected curve. if column 7 -= 0.46 and the operating time at CSM (3.17 column 5) is 0.81 for TMS = 0.2, then column 8 = 0.46/0.81 x 0.2 = 0.114, giving 0.125 as the practical relay TMS
TABLE 11.3 Computer calculated relay settings Pick-up, MVA
Stage
Current grading
Grading margin, s
Fuse rating. A
Plug setting, %
Time multiplier setting
Motor fullload current MVA '
6 x Overload trip time, s
105.00
2.28631
4.64571
■
Thermal setting, %
0.4528
630.0 4.54389
0.24320
120.00
0.43594
11.4315
5.55556
0.33632
100.00
0.11520
17.1473
1.50000
0.34091
150.00
0.19325
57.1577
3.33333
0.43799
100.00
0.17914
76.3184
1.33523
0.44536
125.00
0.23891
,
2.0577
47 I- - 00
2.2863 ,
2.4006
400.0
Reliability manufacturer. Thorough testing of installed systems is lso essential. a The design should ensure that a component is chosen so that it operates around the mid point of its overall rating range. Only components complying with BS9000 must be used. To reduce the failure rate of components such as esistors and capacitors, each must be 'burnt-in'. Dir odes and transistors only require a spot check made ,n them to establish correct operation. The amount of heat generated by components must be kept to a minimum since this can adversely affect the reliability f temperature dependent devices, such as transistors, o in close proximity to them. This problem is further exacerbated for protection relays, because they are always accommodated inside metal or plastic encloures. Where there is a high risk of component failure s or non-operation, redundancy can be used to ensure that high reliability is achieved. Continuous monitoring of the hardware and inbuilt self-checking of microprocessors are now standard features of most digital type protection relays to provide early detection of failure. The reliability of solid state protection relays is improved significantly by using digital rather than analogue type relays. This is because large scale integrated components reduce the number of connections required considerably. Analogue relays require many more components, with consequent increase in the number of electrical connections. Another factor affecting reliability is the immunity of the relay to electromagnetic interference. A power station environment is very heavily polluted with electrical noise and it is essential that the relay is designed and constructed to withstand the effects of such pollution without malfunction or non-operation. To enhance reliability, the CEGB operates a type approval procedure which evaluates fully the performance of the relay under both normal and abnormal operating conditions. This evaluation takes the form of type testing at the manufacturer's works and field rials on selected circuits of the power system. Wherever possible, the field trials are on circuits that are likely to have wide variations in operating conditions. Type testing not only checks the capability of the relay to withstand without deterioration all of the operating conditions it is likely to meet when used in service but also ensures that the design includes a margin over normal service requirement. The following tests are typical of the type tests carried out on protection relays: • Drop. • Vibration. • Electrical stress. • Impulse. • High frequency disturbance. • Spark.
• Radio frequency interference. • Supply variations/interruptions. • Dry heat. • Low temperature. • Insulation resistance. The main criterion used to evaluate the relay is a check that the operating time of the various protection functions is unaffected by the application of the type tests, that correct fault indication is given and that it clears when the relay is reset. However, at the present time the electromechanical type of protection relay is still being manufactured and is still freely available on the commercial market. The demand for such a relay is due mainly to the fact that users prefer to stay with equipment that they are familiar with and which has shown itself to be reliable in operation, resulting in a high degree of confidence in its use and application. Added to this is the fact that some users may wish to replicate an existing protection scheme for a new installation which means using electromechanical relays, thus eliminating the need for additional sets of spares with the attendant savings in spares holding, storage space, administrative costs and the retraining of staff. Another, and perhaps more significant reason for the demand for electromechanical relays, is the market in Third World countries which is influenced by cost and considerations of familiarity, simplicity and reliability. Nevertheless as far as the CEGB is concerned, future protection schemes will tend to be based on the use of solid state technology. Further improvements in the quality of thermal overload protection as applied to motors can be achieved with the digital type relays which are unobtainable from the electromechanical type of protection relay. Use can be made of the temperature detectors in the stator core of the machine during the manufacturing stage. The output signals from the detectors act as inputs to the relay which, in turn, enable the thermal model of the relay to react more quickly to changing temperature conditions in the motor. In addition, further temperature measurements can be taken of the air temperature within the motor by placing detectors at both the inlet and outlet sides of the machine. An overload condition will give rise to an increase in air temperature at the outlet and this signal can be fed into the thermal model as above. These techniques provide enhanced thermal overload protection and will result in a significant reduction in motor winding burnouts, thus minimising the risk of costly repair/replacement and the resulting loss of production which this would entail. The electronic protection relay is generally more costly than its electromechanical counterpart. It is to be expected, however, that with the increasing accept945
Protection
Chapter 11
ance of solid state technology and with the advances made in manufacturing techniques by the application of large scale integration, the cost of equipment will drop significantly in the foreseeable future. The benefits of using a microprocessor-based system have already been outlined. Such a system can easily Form an integrated protection scheme which is particularly useful. The parameters contained in each protection relay can be fed into a junction unit local to the plant and then to a supervisory microcomputer local to the plant, or to some other remote location. The linking of each individual relay into the microcomputer system enables better information to be presented to the operator whilst allowing the ongoing process of monitoring and supervising of the protective system to proceed without affecting the basic level
4
(
1
1
of protection. The system must be designed so that, in the event of a fault occurring in the supervisory computer, the protection reverts to the individual protection fitted to each motor. This ensures that under this type of failure mode, the motor is always protected. Figure 11.60 illustrates a simplified scheme for an integrated protection system. The exploitation of the facilities provided by existing microprocessor-based protection relays to form an integrated system, where a group of motors can be monitored from a central point, is seen as a significant future development. The link between the supervisory computer and the protection junction will be hard wired, although the prospect of using fibre-optic over long distances and in a noisy electrical environment will be reviewed.
Cl co a; atPiZI,C. M 1=1 1r.j IMP !ElarI.Se.Mfr-4. 1 mmm Nu m • wayammois
a am= m
:
0
mmmmm
MfM1•1011/MM
11
kV MOTOR PROTECTION RELAY
=ma
CENTRAL SUPERVISORY COMPUTER
I
PRINTER
111
111
MAIN
JUNCTION BOX
EWINHEMillaiNE
HARDWIRE
3 3kV MOTOR PROTECTION RELAYS OPTIONAL DISPLAYS
OHN E
FIBRE-OPTIC HARDWIRE LINK
a i 41 W MOTOR PROTECTION RELAYS
'JUNCTION aox
Fro. II.60 Plant monitoring data link system
946
Reliability The data from the digital protection devices will displayed local to the plant rather than increasing be the data load at the CCR. From a manufacturing point of view the developinept has reached a stage where working systems are 3‘ a ii a bie. Howes er there is a need for considerable verating experience in order that the best system is cw i ve d, fully reflecting the operating requirements he station. From an economic point of view, the of t increas ed cost of such a system is likely to be offset b ‘ [he benefits obtained through enhanced system reli ability and plant availability. It is unlikely that the above approach will be used on every power station drive. Each motor circuit will be considered on the basis of its importance to the operation of the station and the costs of providing such a system. One of the main benefits of making available information of the sort mentioned, is the diagnostic rea t u res it affords in the post-fault analysis of tripped plant. With conventional relays, like the bimetalic thermal relay, all that is known about a trip condition is that the parameters of the fault condition had reached a value corresponding to the value set on the relay. For example if the motor tripped on unbalance, the relay could not indicate the degree of unbalance present at the time of trip, whereas with the digital type of relay, this information would be readily available. The diagnostic benefits can be further extended by building into the relay a facility which stores the information on a disc or magnetic tape. The information can be retrieved and analysed offli ne and will provide information on the behaviour of the motor over a period of time prior to fault to help explain the reasons for the failures. Such information might indicate, for example, that the drive was unsuitable for the load application or that incorrect settings had been applied to the relay. When compared with the bimetallic relay, the electronic type has the disadvantage that it requires an auxiliary power supply for its operation. Loss of power supply renders the relay inoperative and in the case of digital readout type relays will cause all memorised 1. alues to be lost, a serious disadvantage when the relay has operated and it is necessary to establish the nature and magnitude of the fault. To overcome this problem, a battery back-up can be used which will permit retention of the memorised values for periods ranging from 30 minutes to 3 hours duration, enough time for the plant operator to record the data. Another requirement peculiar to solid state equipment is the ability to withstand often harsh electrical environmental interference conditions without malfunction. In this regard the relay must operate successfully in the presence of radio interference, power frequency, impulse, high frequency disturbance, spark and electrical stress signals. Added to this are the environmental requirements imposed by temperature, humidity, mechanical shock, mechanical vibration and, in the case
of nuclear applications, seismic requirements. [t is acknowledged that, whilst these same physical environmental requirements apply to electromechanical type relays, the solid state relay is far more vulnerable and susceptible to damage from these effects and therefore requires more careful design and construction. An important athantage of all digital type relays is the ability to accommodate changes in protection application. This is possible since all relay functions are written in software and any alterations to circuit application can be achieved by merely changing the software only, the hardware remaining unchanged. This means that standard hardware can be used for different types of protective relay equipment. Modifications to conventional analogue protection schemes often require major changes in hardware. When compared with the electronic analogue type relay, the digital relay offers a significant reduction in equipment size owing to the use of large scale integrated components and microprocessor technology with consequent less space on the relay panel. Additionally, since digital relays only handle small values of current and voltage which are converted into digital form, the burden placed upon current and voltage transformers is significantly smaller than for conventional relays. Typical figures are of the order of 0.01 VA per phase. Owing to the low burden some manufacturers recommend the use of instrument class current transformers. Caution should be exercised in adapting their use since, under maximum fault conditions, instrument class CTs saturate a lot sooner than protection class CTs (as witness in Fig 11.61) with consequent failure to operate. The reliability of digital relays . is enhanced by the self-checking techniques that are built-in. Should any component prove defective, then circuit failure will be indicated by an alarm and/or LED facility.
10% INCREMENT KNEE POINT
+It
50% INCREMENT
NC,. PROTECTIVE CT
*
SECONDARY VOLTS
INSTRUMENT CT
1 EXCITING CURRENT
Fic. 11.61 Instrument and protective CTs
947
CHAPTER 12
Synchronising 1 Introduction 2 Basic terms and synchronising criteria 2.1 Definitions 2.2 Switching operations 2.3 Generator synchronising 2.4 Synchronising errors 2.4.1 Voltage error 2.4.2 Phase error 2.4.3 Frequency error 2.5 Faulty synchronising 3 Synchronising methods 3.1 Manual synchronising 3.2 Automatic synchronising 4 Synchronising facilities and controls 4.1 Synchronising facilities 4.2 Synchronising controls 4.2.1 Steam turbine-generator 4.2.2 11 kV gas-turbine generators 4.2.3 3.3 kV and 11 kV distribution switchgear 4.2.4 3.3 kV diesel generators 5 Synchronising equipment 5.1 Synchronising trolley 5.1.1 Voltmeters 5.1.2 Phase angle voltmeters 5.1.3 Synchroscope 5.2 Guard relay 5.3 Check synchronising relay 5.3.1 Phase measurement 5.3.2 Slip frequency measurement
1 Introduction
Practically all of the generating capacity on the CEGB system is connected, through generator transformers, to the 400 kV or 275 kV transmission system. There are other sources of generation, such as II kV gas-turbine generators used to meet peak demand or emergency generation and some diesel generators generating at 3.3 kV, but these amount to a very small total capacity. These synchronous generators operate in parallel, the total load dispatched being equal to the sum of consumer demand and system losses. The real power is shared in proportion to their driving power and the reactive power in proportion to their excitation. Consumer demand is constantly changing, being characterised by the cyclic daily variation between night time and daytime load, with relatively short periods of rapidly changing load at times of peak demand. 948
5.3.3 Voltage measurement 5.4 Automatic synchronising relay 5.4.1 Steam turbine-generator synchronising 5.4.2 Gas-turbine generator synchronising 5.4.3 Diesel generator synchronising 6 Derivation of synchronising supplies 6.1 Secondary supplies 6.2 Selection of voltage transformer supplies 6.2.1 Single voltage supply 6.2.2 Incoming and running voltage 6.3 Measurement accuracy 6.3.1 Voltage transformers 6.3.2 Interposing voltage transformers 6.3.3 Burdens 6.3.4 Lead resistance 6.4 Synchronising supplies 6.4.1 Steam turbine-generator 6.4.2 11 kV gas-turbine generators 6.4.3 3.3 kV and 11 kV distribution switchgear 6.4.4 3.3 kV diesel generators 7 Synchronising schemes 7.1 Standard schemes 7.2 11 kV distribution circuit 7.3 Steam turbine-generator — generator voltage circuit-breaker 7.3.1 Manual synchronising 7.3.2 Automatic synchronising 7.4 Site commissioning tests 8 References
Under these conditions, the nominal 50 Hz system frequency is controlled partly by the automatic action of the prime-mover governors and partly by changes in total generated output instructed by system control centres and achieved by changing the governor set point. To avoid hunting, governors are designed to stabilise the frequency at a level corresponding to each new instructed output level. Any excess or shortfall in output therefore produces a corresponding increase or decrease in system frequency, a change in output being required to return the frequency to the datum level (50 Hz). By adjustment of the total number of megawatts sent out, the system frequency can be finely controlled and under normal conditions it is maintained within the range 49.8-50.2 Hz. Outside these limits, the CEGB has a statutory duty to maintain the frequency within the range 49,5-50.5 Hz.
Basic terms and synchronising criteria System The CEGB interconnected system of power stations, transmission lines, and switching and transforming stations.
exceptional circumstances, the frequency may fall lower limit but operation below 48 Hz t hi s persist for periods longer than 15 minutes ,bdow ,hou l d not al an y one time. An increase in consumer demand may be met by within limits, the output from generators aldv in service or by increasing the number of generarcl , ,rs oper wing in parallel on the system; the appropriate a,.tion being directed from the system control centre. E ac h time an additional generator is brought into , erv ice, it must be electrically connected to the system by following a procedure called synchronising. Feeder or distribution circuits also need to be paralleled when being re-arranged for reasons such as main[enance. Each time two parts of the system are to be electrically connected this must also be done by following a synchronising procedure as the same requirements in
applY• Generators or systems with low internal impedance cart only be synchronised when certain electrical conditions are satisfied. At the instant of making the connection, the differences in voltage, phase and frequency must be small. Synchronising a generator is therefore the last step in the start-up sequence, performed after the prime-mover has been brought up to operating speed and the generator open-circuit voltage established at its nominal value. By comparing the two supplies, adjustments are made to reduce the differences to within specified limits, at which moment the generator circuit-breaker is closed. The procedure for synchronising two parts of the system is normally less involved. The two supplies are remotely electrically connected and therefore operate at a common frequency. In this case synchronising requires no more than a check to ensure that the voltage and phase are within prescribed limits, at which point the switch is closed. The precision required makes an overall high standard of design essential and a large measure of standardisation in the provision of synchronising equipment has been adopted. The control schemes are based on ,[andard diagrams and only approved equipment is purchased. The equipment needs to be consistently accurate in performance and the design of the synchronising scheme must ensure that the risk of error when synchronising is as small as possible. The design contains in-built safeguards against error or inadvertent operation, since faulty synchronisation would impress a disturbance on the system, with the shock Possibly being sufficient to result in serious plant damage.
Switch The main circuit-breaker or switch disconnector (previously called a switch isolator). Running supply The supply on one side of the switch across which synchronising is to be effected, which is associated with the main system or switchgear bus bars. The running supply voltage and frequency are termed the running voltage and running frequency, respectively. Incoming supply The supply on the opposite side of the switch across which synchronising is to be effected, usually the feeder or generator side to which is connected the supply that is to be brought into synchronism with the main system or switchgear busbars. The incoming supply voltage and frequency are termed the incoming voltage and incoming frequency, respectively. Synchronising The overall operation of ensuring that the two alternating current supplies to be paralleled are, within prescribed limits, in a state of equal magnitude, equal frequency and phase coincidence followed by closure of the appropriate switch (circuit-breaker or switch disconnector) to parallel the two supplies. Figure 12.1 shows the phasor relationship between the incoming and running supply prior to starting to synchronise a generator and at the instant before the switch main contacts close. This definition of synchronising assumes that the two alternating current supplies are capable of being
V
V. f,
INCOMING VOLTS v f
al_,x7NING VOLT
al Phasor relabOnShip at some ostani onor to Synchromsing
RED
a
YELLOW
V II v.
2
Basic terms and synchronising criteria
INCOMING VOLTS i V 1
2.1 Definitions The basic terms used in this chapter are defined as
BLUE
BLUE
RUNNING VOL TS V,
.01 PhaSOr relatiOnSh.0 at the •stant OelOre swItch contacts =se
FIG. 12.1
Phasor relationship between incoming and running supplies 949
Synchronising
Chapter 12
paralleled successfully. For three-phase systems this requires that they have the same nominal voltage and Frequency, are balanced systems (i.e., phase to neutral voltages are of equal magnitude and 120 ° (eke) apart), and also have common phase rotation and phase relationship. Voltage difference The difference in magnitude beI\k,een the incoming voltage and the running voltage. Voltage error The voltage difference at the instant before the switch main contacts close. Phase displacement The electrical angle between the incoming voltage and the running voltage. Alternatively this is termed phase angle, however, both are usually abbreviated to phase. When zero this is termed phase coincidence. Phase error The phase displacement at the instant before the switch main contacts close, Frequency difference The difference in magnitude between the incoming frequency and the running frequency. When the frequency difference is small, this is termed the slip frequency and is usually abbreviated to slip. Example: If the incoming frequency (f t ) is 50.06 Hz and the running frequency (f r ) is 50,01 Hz, determine the slip frequency (f s ): Fs = fi — Fr 50.01 50.06 0.05 Hz
cuit operating time is typically 60-80 ms and the main contact mechanism travelling time is 245-255 ms. Typical operating times for an interposing relay used for remote switching are 35-40 ms and for a closing contactor or solenoid coil 15-20 ms. This last time is normally included in the measured closing time for the switch itself. The closing time for a transmission voltage airblast circuit-breaker is typically 75-80 ms and for a switch disconnector 150-170 ins. For 3.3 kV and 11 kV air-break switchgear the closing times are normally somewhere in the range 150-350 ms. Vacuum and SF6 switchgear closing times at these voltages are around 50 ms, To include all possibilities, the switch closing times for a steam turbine-generator circuit-breaker or switch disconnector at generator or transmission voltage is taken to be within the range 75-350 ms and for 3.3 kV and 11 kV air-break switchgear within the range 100450 ms. The actual value is obtained from site measurement. Under normal conditions, the consistency of closing is assumed to be within ±5 ms of the measured closing time. Changes in switch closing circuit DC auxiliary supply voltage, which may be between ± 10 07o, can cause a further variation in normal switch closing times. Advance angle The angle in advance of phase coincidence at the instant when the switch closing impulse is generated. This compensates for the switch closing ti me .. Correct selection of the advance angle for a given slip frequency results in phase coincidence at the instant the switch main contacts close. Example: A switch has a closing time (t e ) of 300 ms, determine the correct advance angle when the slip freas rate-of-change of quency (f 5 ) is 0.15 Hz. Expressed 0 phase f s 0.15 x 360 = 54 (elec)/s
Alternatively, slip frequency may be expressed as a percentage of the nominal system frequency, i.e.,
Advance angle -= f s x t, = 54 x 0.3 = 16.2 ° (elec)
percentage slip frequency = [slip frequency/system frequency] 100 In the above example, the percentage slip frequency [0.05/50] 100 = 0.13/4. Slip frequency is also a measure of the rate-of-change of phase. Again using the example, the rate-of-change of phase 0.05 x 360 = 18 ° (elec)/s or, conversely, equals 20 s per slip cycle.
Figure 12.2 shows the relationship between advance angle and switch closing time for different slip frequencies. 30
SLIP FAEOLENCY 0 IS Fix
1/ 1
20 0.1 0 Hz
Switch closing time The overall closing impulse response time of the switch when measured from the initiation of the closing signal to the closure of the s witch main contacts. This can be divided into two components; the time taken for the control circuit relays and closing coil to operate and the main contact mechanism travelling ti me. The switch closing time depends on the switchgear type and consequently there is a fair variation in times. For a generator voltage circuit-breaker, the control cir950
3.
005 Hz
I0 L"
J
0 )25
02
03
05
SWITCH CLOSING TIME. s
FIG. 12.2 Relationship between advance angle and switch closing time
Basic terms and synchronising criteria Governor set point This is the setting position of the speed droop characteristic, as shown in Fig 12.4. Before starting to synchronise, the prime-mover speed must be within the governor set point limits, positions (a). Within these limits, the speed can be raised or lowered for synchronising by adjustment of the governor set point. Position (b) shows the governor set to super-synchronously synchronise the generator, see Section 2.3 of this chapter, i.e., with the incoming frequency slightly higher than the system running frequency. Once synchronised the generator prime-mover speed is controlled by the system frequency. The governor set point position now corresponds to the generator
The power output/speed characteristic of the generator prime-mover is controlled by a speed governor an d there are three important parameters related to the governor which affect this characteristic.
Governor speed droop The change in prime-mover ,peed from no-load to full-load expressed as a perenta2e of the no-load speed. This feature is necessary [o ensure that generators share load when operating i n parallel and permits the adjustment of the load t; ontribution made by each generator. The speed droop s adjustable, a low setting being 4% or less up to i 0 a high setting of 25 7o (see Fig 12.3).
FULL LOAD, %
100 -
50-
47
4 18
49
510
51
52
3060
3120
3180
50
51
52
53
3000
3060
3120
3180
FREQUENCY. Hz
28120
288 0
2940 '
30 100 SPEED, omin
Fru. 12.3 Governor speed droop
SYSTEM RUNNING FREQUENCY
FULL LOAD. %
100
50
45
46
47
48
49
FREQUENCY, Hz
2700
2760
2820
2880
2940 SPEED. limn
FIG. 12.4
Governor set point 951
Synchronising producing a small load and is used to control power output. Position (c) shows the governor set at full-load.
Governor rate The rate-of-change of the governor set point if a continuous raise signal is applied. Different governor rates may be applied depending on the operating mode, but for synchronising it establishes the maximum rate-of-change of slip frequency. Typically at synchronisation the governor rate of a steam turbine-generator is 0.05 Hz/s.
2.2 Switching operations Having described the basic terms, the next step is to determine the switches in a power system that need synchronising facilities. This is done during the design of the electrical system by examination of the switching requirements during normal operation, breakdown or maintenance outages, or during and after an emergency. Synchronising facilities are needed at every switch that may be selected to parallel supplies. In a power station, this is at generator voltage circuit switches and at certain switches in the electrical auxiliaries system, such as `incomer"bus section' and 'interconnector' circuits, which can be regarded as distribution circuits. At switches where two supplies cannot be paralled for system design reasons (e.g., fault level), electrical or mechanical interlocks are provided to prevent incorrect operation. In any power system, there are a number of fundamental types of switching operation. At switches fitted with synchronising facilities, these include the following: (a) The circuits being connected are dead uncharged circuits. This is predominantly a testing requirement. (b) The switch connects a live circuit to a dead uncharged circuit. The live supply may be either a system or a generator. (c) The switch connects two parts of a system which are already synchronously connected via a parallel path. The two parts may differ in voltage and phase but the frequency is common. (d) The switch connects two independent systems. The two systems may differ in voltage, phase and frequency. (e) The switch connects a generator tb a system. The t wo supplies may differ in voltage, phase and frequency. Although, strictly, in (a) and (b) there is no synchronising requirement, the synchronising instruments are still used (as described in Section 3.1 of this chapter), and therefore this switching operation is sometimes
termed override synchronising. There is no basic mismatch in (c), although there will be some inequality in voltage and displacement 952
Chapter 12 in phase brought about by circuit loading and transformer differences, etc. The magnitude of the phase displacement to some extent depends on the length and complexity of the parallel path. In a power station, the differences are not usually significant and may be regarded as fixed; however, if the phase displacement between the voltages is changing, as is more likely to occur at a transmission station, this produces an apparent slip frequency. Voltage adjustment is not normally necessary. The type of switching operation described in (d) i s usually associated with a system split, i.e., the system has become subdivided into two or possibly more parts as the result of a fault or major incident; this arises infrequently at transmission stations. It may then be necessary to adjust generating station(s) frequency and voltage, as appropriate, if the two system parts are outside prescribed limits. A similar situation occurs at a power station when synchronising the emergency supply system to off-site supplies following the earlier loss or disconnection of the latter. Again, this operation is rare. The switching operation described in (c) is usually termed 'check synchronising' (after the check synchronising relay described later in this chapter) and that in (d) is termed 'system synchronising'. However, since the two forms of synchronising involve the system, both switching operations are regarded as system synchronising for the purposes of this chapter. Furthermore, in (c) the two parts of the system are synchronously connected, termed synchronous system synchronising; whilst in (d) the two parts of the system are not of the same frequency, termed asynchronous system synchronising. With both switching operations power redistribution occurs on switching. Similarly, for the purpose of this chapter, switching operation (e) is termed generator synchronising. Since as with (d) the two supplies are not of the same frequency, this is termed asynchronous generator synchronising. Means of adjusting both voltage and frequency are necessary. This is the most common form of switching operation. There are two methods of generator synchronising: • Super-synchronously synchronising, with the incoming frequency higher than the running frequency. • Sub-synchronously synchronising, with the incoming frequency lower than the running frequency.
2.3 Generator synchronising Power station generators will also operate as synchronous motors, i.e., instead of being mechanically driven to produce electrical power, they run as motors, drawing power from the system. Without further adjustment of the governor, this will occur on synchronising if done sub-synchronously or possibly after synchro nising with the two frequencies almost equal, should the system frequency rise immediately. Motoring can
Basic terms and synchronising criteria cre the prime-mover; in steam turbine-generators, "' Er., ect motoring affects turbine final stage vacuum „ r olablade cooling. To prevent motoring or the opera., 11 o f r everse power trips, synchronising must take uper-synchronously. The prime-mover speed gov1[:1,2C S . se t with the incoming frequency above the nor s frequem:y (as shown in Fig 12.4) and the genautomatically picks-up load on synchronising. rile load pick-up must only be a small proportion full-Load output, typically 1-5%. To combine this rovireme nt with satisfactory synchronising, the primeoi,er speed is increased to take the incoming frem ey above the running frequency, and then slowly ien -,:dacecl. Synchronising follows when the slip frequency less than the maximum allowed and is within the .pecilied load pick-up band. The load pick-up is determined by the speed droop , e i[i ri g and the slip frequency (governor set point). This 2iven by: :o a
iro load pick-up = 71:1 slip frequency
0
x 100
% speed droop [\arnple: Determine the slip frequency band for a load pick-up between 1% and 5%, with a speed droop of 4ro and a system frequency of 50 Hz.
iro slip frequency = 0
7o load pick-up x % speed droop 100
Slip frequency = ¼slip frequency x system frequency 100 Rs:Jrranging and substituting: Slip frequency for 1% load pick-up =
generator loading. As the prime-mover is accelerated up to synchronous speed, the difference between the lower incoming frequency and running frequency is progressively reduced, synchronisation commencing when the difference is less than the maximum slip frequency allowed. Where the above considerations do not apply, synchronising may be performed using either method when within the maximum slip frequency allowed.
2.4 Synchronising errors Although the ideal conditions for generator synchronising are likely to be approached closely, for a number of reasons there are limits to the accuracy which can be obtained. These include matching and measurement accuracy, and where a small slip frequency is required for load pick-up reasons, as already described. Fortunately, it is not necessary that the exact conditions be attained, as true synchronism is brought about after the two supplies have been synchronised through the action of generator synchronising currents. These flow in the stator windings with consequent effects imposed on the rotor and persist until self-extinguished when the synchronising errors have been eliminated. On synchronising, the initial sub-transient current produces the most effective corrective response. Thereafter, the current transient declines in magnitude, the rate depending on the generator transient reactance and the progressive decrease in the synchronising error. Frequency difference and phase displacement, which demand rotor movement relative to the air gap rotating field, require the flow of real power (called synchronising power) which produces a synchronising torque. It is this torque, acting on the generator rotor and coupled drive together with governor and damping effects, which captures and locks the rotor into the synchronous position. Initially, the rotor overshoots and tends to oscillate or hunt about the synchronous position. Additional damping is provided by rotor damping bars and with normal synchronisation the oscillations quickly decay.
cr7o load pick-up X Wo speed droop i 100 system frequency 100 = [1 . x 4/100] x 50/100 = 0.02 Hz Slip frequency for 5% load pick-up = 15 x 4/100] x 50/100 = 0.1 Hz Slip frequency band = 0.02 to 0.1 Hz
Cenerators are synchronised sub-synchronously where rapid synchronisation is required, normally as part of a i uilY automatic start-up control sequence which includes
2.4.1 Voltage error The condition immediately after synchronising is shown in Fig 12.5, where the generator incoming voltage V; per phase is slightly less than the system running voltage V, per phase. The two voltages are almost coincident, the voltage error being represented by the phasor V. This results in the generator drawing a synchronising current I s from the system approximately in quadrature with voltage V. This similarly leads the running voltage V, and is essentially a magnetising current which strengthens the generator magnetic field. Synchronism is rapidly achieved with predominantly reactive power taken from the system. The converse also applies if the incoming voltage Vi is slightly higher than the running voltage V„ when 953
Synchronising
Chapter 12
SYNCHRONISING VOLTS I V,)
IN C OMING VOLTS V
r
RUNNING VOLTS
SYNCHRONISING CURRENT NOT TO SCALE
FIG. 12.5 Voltage error
a lagging de-magnetising current flows from the system to the generator to weaken the generator magnetic
2.4.2 Phase error
The immediate effect after synchronising with the generator incoming voltage V, displaced behind the system running voltage V, by an angle 0 is shown in Fig 12.6. The voltage phasor between corresponding phases V s , results in the generator drawing a synchronising current from the system. As the stator impedance is predominantly reactive, this is nearly in quadrature with voltage V„ which is nearly in phase with the running voltage V,. Real power is taken from the system which produces the torque required to pull the rotor into synchronism. The converse also applies if the incoming voltage V; leads the running voltage V,. The generator produces a synchronising current, the active component of which produces the required synchronising torque. 2.4.3 Frequency error
If the generator incoming frequency (fi) is slightly greater than the system running frequency (f r ) on synSYNCHRONISING VOLTS (V S )
INCOMING V OLTS (V)
RUNNING VOLTS ( Vd
NOT TO SCALE
Fro. 12.6 Phase error 954
chronisation the incoming and running voltages are superimposed onto each other; the resultant voltage, represented by the voltage (V,), is a pulsating wave whose magnitude at any instant is the voltage difference (V, V r ) as shown in Fig 12.7. This voltage is obtained by reversing the phase of the running voltage (V,) and adding the reversed wave to the incoming voltage (V,). This results in a synchronising current (I s ) being drawn from the higher frequency generator sup. ply, the real power component of which produces the synchronising torque required to achieve synchronism. Similarly, if the situation is reversed and the system running frequency is higher than the generator frequency, then real power is taken from the system. If the frequency difference in Fig 12.7 continues, the amplitude of the resultant pulsating voltage continues to increase with each cycle until a maximum of (Vi + V r ) is reached when the two voltage waves are in antiphase. If further continued, the resultant voltage progressively decreases as the two voltages move back into phase. The envelope of the modulated wave (V, — V,) is shown dotted. The beat frequency of the modulated wave is equal to the slip frequency. If the slip frequency is small, e.g., 0.05 Hz or 20 s/slip cycle, it takes 10 seconds for the resultant voltage to rise from being zero at phase coincidence to peak value. With the voltage and phase matched, the synchronising current produced by a small slip frequency is generally not significant since the change to a high resultant voltage is not rapid. It also follows that if the voltage and phase error are small, this does not greatly increase the synchronising current.
2.5 Faulty synchronising For each synchronising condition, as the error increases in magnitude so does the disturbance or shock this imposes on the generator and the system. In particular, large phase displacement and frequency differences result in generator hunting, a condition where the synchronising torque accelerates the rotating system, overpowering the rotor damping, etc., resulting in the rotor swinging past the synchronous position under its own inertia. An opposing torque is produced to retard and reverse the direction of motion, the cycle continuing until eventually the oscillation is reduced by damping and the rotating system held in the synchronous position. To produce the fluctuating torque required, the generator has to alternately supply and absorb sizeable synchronising power with an initial transient which can involve currents in excess of generator rating. Mechanical forces are proportional to the squares of the currents with the maximum mechanical force related to the peak current value. In this respect, the duration of the synchronising torque is not as important as the magnitude and number of force reversals. The heavy power transfer results in a voltage disturbance which may also adversely affect the power system to which the generator is connected, although
Synchronising methods
•
INCOMING VOLTAGE
V. = RUNNING VOLTAGE •
= SYNCHRONISING VOLTAGE
f, = FREQUENCY OF V, FREQUENCY CF
ENVELOPE OF MODULATED WAVE
V - V,
+N.
SLIP FREQUENCY
NOT TO SCALE FIG.
12.7 Frequency error
It is highly unlikely that this would result in transient instability of the system. The parameters which determine the power swing on the system can be summarised as: • Phase angle and slip frequency between the two voltages. • Voltage magnitude and system loop impedance. • Relative size of the generator and system (connected capacity, inertia and fault level). • Speed of governor response. • Mechanical damping of the turbine-generator rotating system. The effect of the disturbance on a turbine-generator is to stress the stator and rotating parts, depleting design life expectancy in certain respects, typically: • Stator end windings, being the weakest part of the stator, may distort and in so doing, damage the end insulation. Although there is little likelihood of permanent deformation, small elastic deflections may eventually adversely affect the insulation. • Torsional oscillations stress the shaft system and in particular the shaft couplings. • LP turbine blade root stress due to the effects of blade dynamics.
If the divergence in slip frequency is sufficiently large, the pullout torque of the rotor is exceeded and generator pole slipping occurs.0 Faulty synchronising at a phase angle of about 120 gives rise to high shaft torques and stresses, which may exceed those resulting when a three-phase short-circuit is cleared. 3 Synchronising methods Two quite different methods have been developed for synchronising. The first and oldest method, dating back to the nineteenth century, is performed by the operator and is called manual synchronising. For many years, manual synchronising was carried out using a set of three lamp bulbs. These were connected across the supplies to measure the sum of the two voltages. When the two voltages were equal and in phase, the voltage across the lamps was at maximum and the lamps were at their brightest. This was known as the 'lamp bright' method. Today, the correct synchronising conditions are determined by observing a set of instruments. The second method is automatic synchronising and employs a purpose designed control unit to perform the complete operation without any need of supervision by the operator. Automatic synchronising is initiated within the operating range of the control unit by the operator, or by an auxiliary relay if incorporated into a larger automatic control scheme. 955
Synchronising Both methods are used for system and generator synchronising but only automatic generator synchronising incorporates voltage and frequency control. At a power station, system synchronising is carried out manually and generator synchronising is normally carried out automatically, using a device called an automatic synchronising relay. Manual synchronising facilities are provided as back-up for generator synchronising in case the automatic synchronising relay fails. Both methods are also used for system synchronising at transmission stations. Automatic synchronising employs a device called a system synchroniser used, for example, in autoswitching schemes such as delayed auto-reclose.
3.1 Manual synchronising The instruments provided for manual synchronising are an incoming voltmeter, a running voltmeter, a phase angle voltmeter (i.e., an instrument which measures a voltage corresponding to a phase angle) and a synchroscope which measures slip frequency and phase. The three voltmeters are used to synchronise when conditions are synchronous, i.e., system synchronising. The incoming and running voltmeters plus the synchroscope are used to synchronise when conditions are asynchronous, i.e., generator synchronising, and when needed for system synchronising. In brief, to system synchronise, both voltages are first measured and compared. With zero frequency difference shown by the synchroscope, the phase is measured with the phase angle voltmeter. If both voltage and phase measurements are within prescribed li mits, as is normal, the switch is closed. To generator synchronise, one voltage (which may be the incoming or running voltage) is adjusted as necessary to reduce any voltage difference to within prescribed limits. The incoming frequency is then adjusted until the slip frequency is less than the maximum allowed. For load pick-up the adjustment must produce the incoming frequency high and falling to super-synchronously synchronise. Switch closing follows as soon as the phase is within prescribed limits and is initiated at the instant the phase is at the correct advance angle, or as close to this as can practicably be achieved. Repetition of the synchronising instruments at each switch control position at which synchronising facilities are required is not necessary. The synchronising instruments themselves may be used to synchronise at any switch control position if the voltmeter scales are changed, these are therefore combined (as far as is allowed) into a common set. The synchronising instruments are housed in a mobile trolley to ensure that the indications are clearly legible at each switch control position if located at more than one control panel, as is the case in a power station. To accommodate four system voltage levels (i.e., 3.3 kV, 11 kV, generator and transmission voltages), two separate sets of instruments are provided, each with dual scale voltmeters. 956
Chapter 12 To transfer the instrument circuitry, the trolley i s equipped with two leads and plugs, and each switch control position at which synchronising facilities are required is provided with a synchronising socket (this is not always necessary and a common socket may be provided at a convenient point). Prior to use, the synchronising trolley is positioned adjacent to the switch control position concerned and plugged into the socket to prepare the circuitry for synchronising. The level of operator ability required depends on the switching operation, but at least demands a technical understanding of the principles involved and o r the accuracy that must be applied. For system synchronising, the operation normally amounts to little more than a check of voltage and fixed angular displacement and little skill is involved. With a frequency difference, the full procedure is required. As the slip frequency is reduced, sensitive adjustments to primemover speed need to be made to obtain the desired response. The characteristics of the prime-mover governor may also lead to some change of slip near the point of closing the switch. In particular, attention must be paid to the selection of the correct advance angle for initiating the switch closure, estimated from the product of the observed slip frequency in ( ° elec)/s (estimated from the time taken for the phase to traverse a given angle, e.g., 360 0 ) and the known switch closing time for the switch concerned. From experience, this process is often simplified to a fixed angular allowance. In addition to being competent in the above respect, the operator must be fully aware of the function he is performing and conscious of the consequences of error and the result of incorrect operation so that no chances are taken. As a safeguard against the risk of human error or malfunction of the synchronising instruments resulting in the connection of unsynchronised supplies, a device called a check synchronising relay is added. This separately measures the voltage, phase and slip frequency, inhibiting the switch closing signal unless the supply differences are within preset limits. The employment of this relay is termed check operative. To assist the operator, a 'check synch monitor' lamp can be added to indicate when satisfactory synchronising conditions are present. The slip feature is switched out of service for generator synchronising to permit the switch to be closed with a slip frequency greater than the relay setting permits, as required for load pick-up. (If motoring is not a consideration, e.g., gas turbines, this feature may be retained if preferred for operational reasons.) Check synchronising relays are also used as system synchronisers in auto-switching schemes at transmission stations. In this application, the check synchronising relay initiates the switch closing signal when the differences between two supplies are within preset limits. The synchronising equipment is also provided for manual override synchronising, i.e., when one supply
Synchronising methods is live and the other supply is dead or both supplies ad, as an additional safeguard against operator are d e Since this supply condition would operate the error. k synchronising. relay, a check synchronising relay „. hec bypass facility is fitted. In this switching operation, he voltages are measured and having checked that nlv t r:chronising is not required, the switch is closed. Th e by-pass facility is termed check inoperative and s only used under clearly defined conditions. However, i he check synchronising relay may also have to be t bv,passed in an emergency, manual synchronising then ing only on the synchronising instruments. This re l y y be necessary if both the automatic and check ma .i.,.nehronising relays have failed and it is considered essential to provide additional generation. It is not intended that the check synchronising relay be used as an automatic synchroniser when generator Nynehronising. The operator must not be allowed to transfer all responsibility to the relay by the premature operation or holding over of the control switch while v,aiting for the relay inhibit to be released. Therefore a device called a guard re/ay is fitted. This permits the ,..heck synchronising relay to decide whether the control switch was operated before or after prescribed synchronising conditions were reached, inhibiting the close signal if before. For the same reason, a guard relay is also installed for system synchronising when this involves a frequency difference. The relay may also be used to prevent a standing output signal from a faulty check synchronising relay permitting the switch to be closed. The advantages of manual synchronising are as follows: • The operator has complete control of the switching operation. • The requirements for each type of switching operation are accommodated in a common set of equipment. • Equipment can be transferred between circuits with the same check synchronising relay setting.
frequent and an automatic synchronising relay is not provided. A guard relay prevents premature switch closing and in exceptional circumstances the check synchronising relay may be by-passed. Minor disadvantages are the inconvenience of having to move the synchronising trolley before and after use and the restriction in access to other controls when synchronising in an area with limited free space. Where seismic requirements are included, a parking position is provided to prevent unrestrained movement.
3.2 Automatic synchronising The action of an automatic synchronising relay in synchronising a generator is similar to manual synchronising but with improved speed and accuracy. On being switched into service, the incoming and running voltage and frequency are monitored by matching circuits which send out signals to controllers to reduce the differences to within permissible limits. When these conditions are met, contacts on phase sensors close at the correct advance angle to initiate the closing of the switch. Synchronising may be performed sub-synchronously (incoming frequency low), super-synchronously (incoming frequency high) or within a maximum slip frequency if there is no requirement for a particular method. Table 12.1 shows the synchronising method employed by the CEGB for each type of generator. The relay is preset, selecting the synchronising method, maximum slip frequency setting, voltage error setting, switch closing time and speed signals to the primemover speed governor. Automatic synchronising relays, unlike the synchronising instruments, are regarded as fixed equipment and provided on a one per generator basis. There is no requirement for interchangeability, although relay models for this duty are available with external facilities for the selection of up to three different switch closing times. There is one exception where a common auto-
• Instruments required are relatively basic and unlikely to fail. • Common mode failure cannot occur when manual synchronising is used as the back-up to automatic synchronising (as may happen if back-up is provided by a second automatic synchronising relay).
TABLE
12.1
Synchronising method for each type of generator
Generator type
Synchronising method
Reason
Steam turbinegenerator
Super-synchronously
Prevent motoring (prime-mover damage)
• Low capital cost of the equipment, if considered in relation to its wide application.
Gas turbine
Sub-synchronously 0)
Rapid synchronisation
In summary, manual synchronising supervised by a Lheek synchronising relay is appropriate for the less demanding requirements of system synchronising, as called for in periodic maintenance switching, etc. Manual synchronising has an advantage as back-up for generator synchronising where automatic synchronising is the normal method and also for use at switches where generator synchronising is expected to be in-
Pumped-storage Motoring mode Super/subsynchronously"
Maximum chance of synchronisation
Generating mode Sub-synchronously
Rapid synchronisation
Diesel generator Super-synchronously
(i)
Prevent motoring (reverse power relay tripping)
May be done super-synchronously if required for operational reasons
(ii) Using starting equipment (automatic synchronising relay does not control the machine speed)
957
Synchronising matic synchronising relay may be used for diesel generators. As described later, this is a non-essential duty. The advantages of using an automatic synchronising relay are as follows: • The complete synchronising operation is carried out automatically. • Synchronising is performed consistently, with a degree of precision and final accuracy which cannot be approached by manual means. • Synchronism is achieved rapidly, minimising the synchronising time. • The resultant disturbance to the generator and system after the switch closes is kept to a minimum. • Synchronising can be incorporated into a comprehensive unit automatic start-up sequence. • Operator work load is reduced when synchronising has to be performed at regular intervals or a number of generators need to be synchronised in succession over a short period of time. • It is capable of operating with falling voltage and frequency. • The risk of human error is largely removed. • The demand for skilled operating staff is reduced. • It permits the synchronising of remotely operated plant at unmanned generating stations. For the above reasons, especially accuracy, automatic synchronising is the normal method of steam turbinegenerator synchronising. Usually, reasonable time is available for this operation, but it may have to be done quickly when system conditions demand rapid connection of a generator for system security or load despatch reasons. Automatic synchronising is essential for rapid synchronisation of the gas turbines used for emergency generation, which are required to be brought from rest to full-load in less than two minutes. In the event of a transmission system disturbance causing a fall in frequency, a low frequency relay initiates starting at a preset value. As a design basis for operation, the severest system conditions are assumed to be a frequency fall of I cycle every 25 seconds down to 40 Hz and a voltage fall of 1.5% every 25 seconds. The ability to synchronise with a falling frequency is also used at pumped-storage power stations when synchronising in the pumping mode, as the machine speed falls too quickly for an operator to respond manually.
4 Synchronising facilities and controls 4.1 Synchronising facilities The major synchronising facilities in a power station are remote from the switchgear and are situated in the 958
Chapter 12 central control room at the unit control desk and at other control panels, i.e., the electrical auxiliary and transmission system control panels and gas-turbine remote control panel, if provided. Gas turbines are also provided with synchronising facilities at the local control panel as is switchgear in switchrooms or at plant locations if required. The synchronising facilities at each of these locations for three standardised generator/transmission voltage switchgear schemes and the electrical auxiliaries system, including gas turbine and diesel generator switchgear, if provided, are shown in Table 12.2. This does not include the synchronising facilities for the transmission station switchgear at the transmission control panel, as these extend beyond the scope of this chapter. The synchronising facilities for the steam turbine. generator are located at the unit control desk, irrespective of whether synchronising is with generator or transmission voltage switchgear. For generator voltage switchgear (Table 12.2, scheme (a)), synchronising normally takes place across the generator voltage circuitbreaker and automatic and manual synchronising facilities are provided. Automatic synchronising is the normal mode, backed up by manual synchronising with check operative. Manual synchronising with check inoperative is also provided when it is necessary to bring a generator into service with the transmission supply absent. In addition, manual synchronising facilities, with check operative and check inoperative, are provided for the associated transmission voltage circuitbreaker. Manual synchronising with check operative is provided for re-synchronising the steam turbinegenerator on restoration of transmission supplies following loss or disconnection. Manual synchronising with check inoperative is prevented, except when the generator voltage circuit-breaker is open. In both transmission voltage switchgear schemes (Table 12.2, schemes (b) and (c)), the steam turbinegenerator is synchronised across the transmission voltage circuit-breaker and switch disconnector, respectively. Automatic and manual synchronising facilities are provided for both schemes. Automatic synchronising is the normal mode while manual synchronising with check operative is available as back-up. Manual synchronising with check inoperative is also provided for the circumstances referred to in scheme (a). Each steam turbine-generator switch is equipped with a fixed set of synchronising equipment. This includes the automatic synchronising relay, where applicable, the check synchronising relay and guard relay plus the associated control circuitry. The one exception is for the manual synchronising instruments mounted on the synchronising trolley, which are common. The main 3.3 kV and 11 kV electrical auxiliaries system is set out as a mimic diagram on the electrical auxiliaries control panel. This consists of standard symbols, signs and lines, etc., arranged in such awaythat they represent the circuit layout of the switch gear, transformers, generator main plant, etc. Different
Synchronising facilities and controls TABLE 12.2 Synchronising facilities
Synchronising Controls Switch
Circuit
a. T-si-s , ssor ;ci!age .::."c3.31! breaker with generator .0 vga o.v
Facility
Location Unit control desk
on
Generator voltage switch Automatic manua! ii Check operative rill Check inoperative Tmraarnsum a il ssion voltage circuit-breaker :!i Check operative Check .noperatve •
C:RCulTAIREAKER
Transmission voltage oircuit-breaker Automatic:manual ti) Check operative (11) Check inoperative
.lb) Trarsmission voltage Circuit-breaker with no switch at generator voltage
TRANSMiSSION CdRCUIT BREAKER
Transmission voltage switch disconnector Automatic, manual (i) Check operative (HI Check inoperative
Transmission voltage switch disconnector (with transmission voltage circult•breakert with no switch at gene:33.10r voltage
6
GO
SwiTCH DISCONNECTOR
TRANSMISSION C;FICU.7 SPEAKER
gaS
Gas turbine local control panel
Automatic
Gas turbine remote control panel'
Automatic:manual (i) Check operative (ii) Check inoperative
Circuit-breaker
3 3kV and • •kV oistn. cvgevr
Circuit-breaker
3 33kV evlor Circuit-breaker
Electrical auxiliary control panel
Manual
(i) Check operative uI Check inoperative
a) Electrical auxiliary control panel
Automatic:manual (i) Check operative (ii) Check inoperative
(b) Diesel generator local control panel
Automatomanual (i) Check operative (ii) Check inoperative
Electrical auxiliary control panel
Automatic
diled when generator voltage switch closed
colours identify each system voltage and limited opera[Lona] information is displayed. To remotely open and dose each circuit switch, a control switch is fitted at 3ach circuit switch position. A synchronising socket is Installed near each circuit control switch where manual nchronising facilities are required. A common set of ..nchronising equipment is provided including check )ynchronising relay, guard relay and associated control :ircuitry mounted inside the synchronising trolley. Manual synchronising with check operative is in)tailed for system synchronising, with manual synchronising and check inoperative normally available in the absence of one or both supplies. identical facilities, .ocated in a 3.3/11 kV synchronising trolley, are proicled in switchrooms, etc., if these are required. Synchronising facilities for 11 kV gas turbines are based on the requirements of Design Memorandum ,
,
066/1 11]. The main facilities are located at the gas turbine remote control panel and automatic and manual synchronising facilities are installed on the same operating basis as already described in scheme (a). The common synchronising trolley equipment is used for manual synchronising. Identical automatic synchronising facilities are provided at the gas turbine local control panel, which is required to contain all the controls and instrumentation including the automatic synchronising relay necessary to operate the plant. Although used primarily for commissioning, local facilities permit plant operation should the remote facilities fail. Diesel generators at 3.3 kV are not used as sources of generation to meet system demand but to provide essential power station supplies in an emergency following the loss of external supplies. There is no set 959
"1" Synchronising standard for the application of diesel generator synchronising facilities, so two recent designs at nuclear power stations are described. Automatic synchronising facilities are provided, although they are not used in an emergency. They are included for operator convenience during the regular 'on load' testing necessary to demonstrate the high level of availability required or such plant. With the first scheme, two additional synchronising [Folio s, equipped for manual and automatic synchronising, are provided for synchronising at the electrical auxiliaries control panel. In the second scheme, automatic synchronising facilities are provided for each diesel generator at the electrical auxiliaries control panel, and automatic and manual synchronising facilities are provided at each local control panel. Manual facilities, with check operative and check inoperative, are provided on the same operating basis as already described.
4.2 Synchronising controls Many precautions need to be incorporated into the design of a synchronising scheme to prevent error or incorrect operation. Of particular concern is that part of the operation done manually; therefore, the synchronising procedure includes measures designed to minimise the risk of human error by making each manual step in the operation the end result of considered action on the part of the operator. Several of these measures, which are concerned with the operation of the synchronising equipment, have already been described in Section 3 of this chapter. Further measures are included in the preparatory actions performed prior to starting the actual synchronising operation and, for manual synchronising, extend to the operation of the circuit control switch. The measures included in the preparatory actions, which apply to each circuit equipped for synchronising, ensure that: • The same basic procedure is followed to prepare each circuit for synchronising. • The circuit switch cannot be closed without first
following the procedure of actuating a control switch to select the synchronising mode, i.e., automatic, manual with check operative or inoperative. • Secondary voltage circuits are not established until the control selector switch is actuated. At generator and transmission voltages, certain 'auto
synch/manual synch' control selector switches are made key-operated and a separate key-operated control selector switch is installed for the 'check operative/check inoperative' facility. In addition, no synchronising operation on a transmission voltage switch can take place at the unit control desk without first actuating a keyoperated 'generator unit desk' control selector switch located on the transmission control panel. 960
Chapter 12 A proprietary design of miniature lock is fitted for the key-operated control selector switches, which can only be operated with the key in position. The key i s free to be removed in the 'off' position and is trapped in all other positions: when not in use, the keys are normally kept in a separate key parking socket. Th e key patterns produced are coded by the manufacture r and a small number of these have been selected by the CEGE3 to form different key groups. Each key group is dedicated to a particular control selector switch function. Two key groups are used at the unit control desk. One key group (ov) is fitted to the 'check operative/ check inoperative' control selector switch and the other key group (k) is fitted to the synchronising mode control selector switch in the generator voltage switchgear scheme (a) (key-operated control selector switches may be fitted with the other two schemes). The third key group (s), located at the transmission control panel, is used to synchronise a transmission voltage switch. The purpose of this key group is to ensure that synchronising can only take place on one circuit at a time at the transmission station. To enable synchronising to be carried out in the central control room, the 'local/remote/test' control selector switch at the circuit switch local control panel or switchboard must be selected to the 'remote' position. This transfers operation control from the local 'open/ neutral/close' control switch to a discrepancy control switch, which is the final initiating control whose design features need to be described. Discrepancy control switches inform the operator of the circuit switch position while going through the motion of actuating the switch. On being rotated through a quarter of a turn in the appropriate direction, an internal discrepancy light flashes to alert the operator that the switch indicates (by a coloured line or arrow on a white background) the wrong sense. The switch will continue to flash if left in the wrong sense. Having cautioned the operator, with further rotation the 'open' or 'close' signal is initiated, and as soon as the circuit switch has operated, the discrepancy light extinguishes to inform the operator that the switching operation is now complete. On release, the control switch has an inbuilt return action to bring the switch to rest indicating the new circuit switch position. The operation of the synchronising controls can now be described. 4.2.1 Steam turbine-generator
Figure 12.8 shows the steam turbine-generator synchronising controls on the unit desk. Voltage and speed controls The voltage at the low voltage terminals of generator transformers must be kept at 100 0/o of rated voltage at all times to maintain the voltage constant at the auxiliaries connected via unit transformers to this point.
Synchronising facilities and controls
GENERATOR SYNCHRONISING
._
23 5kV _— SYNCH SELECTION 1 i OFF AUTO . ,ki ANUAL; )SYNCH SYNCH
400kV SYNCH SELECTION 1 I OFF 1 I MANUAL SYNCH r--,
! AUTO SYNCH
1,.F
(k)
S._ CHECK SYNCH
CHECK SYNCH I
OP
i
OP iNOP
(0v)
(ov)
BUZZER
1 ,-
,
OPEN 1 CLOSE ,,-1
OPEN I I CLOSE i
,
/1
LAMP I TEST
SYNCHRONISER LOCKED OUT
%
1 CHECK SYNCH MONITOR
..
NV SYNCHRONISE AVAILABLE
\
/I /
CHECK SYNCH MONITOR
CIRCUIT BREAKER
. CIRCUIT BREAKER
\ I / — INDICATOR LAMP / I \
SYNCHRONISING COMPLETE
FIG. 12.8 Steam turbine-generator synchronising controls on the unit desk
Steam turbine-generators are therefore fitted with automatic voltage regulators which are normally set to maintain the terminal voltage at its nominal value. Voltage matching is therefore carried out using the een crator transformer on-load tapchanger by raising and lowering the tap position. The tapchanger alters the transformer open-circuit %oltage by adjusting the effective number of turns in he high voltage winding. In total, there are nineteen ;ap positions, with a voltage step of 1.11% nominal between each tap position. 'Raise' and 'lower' refers to changing to a higher or lower tap position number, respectively. If synchronising at the generator oltage circuit-breaker, this is by adjustment of the running voltage and, at the transmission voltage switch, b!, adjustment of the incoming voltage. With the late r, the 'raise' tapchange operation reduces the transormer open-circuit voltage and, similarly, the 'lower' iapchange operation increases the transformer open-
circuit voltage. The turbine speed governor set point controller (as described raise
in Section 2.1 of this chapter) is used to or lower the generator incoming frequency.
Generator voltage circuit-breaker (with transmission voltage circuit-breaker) scheme
Manual synchronising of the steam turbine-generator ommences with the connection of the synchronising trolley plug to the generator- voltage circuit breaker
c
-
synchronising socket. The selection of manual synchronising is made by key operation (k) of the 'off/auto synch/manual synch' control selector switch to the 'manual synch' position. Actuation connects the incoming and running supplies to the synchronising instruments. The supplies are also connected to the check synchronising relay with key-operated (ov) 'check inoperative/check operative' control selector switch selected to the 'check operative' position. The auxiliary power supply is permanently connected to the check synchronising relay. The generator voltage circuit-breaker is closed by operation of the discrepancy control switch, provided that the check synchronising relay output contacts have previously closed. Satisfactory conditions are indicated by the illumination of a check synchronising relay monitor lamp. The guard relay inhibits the close signal and the display of the check synchronising monitor lamp if the discrepancy control switch is prematurely operated. Actuation of the key-operated (ov) selector to the 'check inoperative' position energises an auxiliary relay which by-passes the check synchronising relay output contacts. Manual synchronising in this mode is normally restricted to closing onto a dead circuit. Selection of automatic synchronising by key operation (k) of the control selector switch to the 'auto synch' position, energises auxiliary relays which connect the incoming and running supplies and the auxiliary power supply to the automatic synchronising relay. With the 961
Synchronising equipment prepared and the steam turbine-generator running, manual initiation of the 'auto synch' start button instructs the automatic synchronising relay to begin. synchronising. Manual synchronising facilities for the transmission 1,olta. ,2e circuit-breaker are available at the transmission control panel and the unit control desk. To establish manual synchronising at the unit control desk, the key-operated (s) control selector switch at the transmission control panel is selected to the 'generator unit desk' position. This illuminates a `HV synchronise available' lamp at the unit control desk. The initial preparation for synchronising at the unit control desk is by plug connection of the trolley. Selection of manual synchronising is by actuation of key-operated (k) 'off/manual synch' control selector switch to the 'manual synch' position. This connects the incoming and running supplies to the synchronising instruments and to the check synchronising relay provided the key-operated (ov) 'check operative/check inoperative' control selector switch is selected to the 'check operative' position. The auxiliary power supply to the check synchronising relay is permanently energised. The circuit-breaker is closed by operating the discrepancy control switch, with the conditions the same as described for the generator circuit-breaker. NIanual synchronising without check synchronising is by operation of the key-operated selector (ov) to the 'check inoperative' position. Manual synchronising in this mode is inhibited, except when the generator voltage circuit-breaker is open. Transmission voltage circuit-breaker (with no generator voltage circuit-breaker) scheme
To establish either manual or automatic synchronising at the unit control desk, the key-operated (s) control selector switch at the transmission control panel is selected to the 'generator unit desk' position. Synchronising is then carried out as for the generator voltage circuit-breaker except that the transmission voltage circuit-breaker discrepancy control switch is used. Transmission voltage switch disconnector (with transmission voltage circuit-breaker) scheme
The synchronising controls are transferred to the unit control desk by selection of 'generator unit desk' on the key-operated (s) control selector switch at the transmission control panel. Synchronising is again carried out as for the generator voltage circuit-breaker except that the transmission voltage switch disconnector discrepancy control switch is used. 4.2.2 11 kV gas-turbine generators
Gas turbine synchronising facilities are available at the gas turbine remote control panel after the selection of 'remote' at the gas turbine local control panel. 962
Chapter 12 To synchronise manually `no-load' is selected at the control selector switch and to synchronise automatically either 'peak' or 'standby' is selected. Manual synchronising begins after the gas turbine has been started and run-up under the supervision of the automatic sequence control system. It commences with the insertion of the plug into the synchronising socket which connects the auxiliary power supply to th e check synchronising relay. Synchronising is with 'check operative' selected at the control selector switch o n the synchronising trolley which connects the running voltage and the incoming voltage to the synchronising equipment. The voltage is raised and lowered by adjustment of the automatic voltage regulator (this may be by adjustment of the generator transformer on-load tapchanger with peak-lopping gas turbine schemes). The speed is altered by adjusting the gas turbine speed governor set point controller. Closure of the II kV gas turbine circuit-breaker, which is initiated by operating the discrepancy control switch, cannot be carried out until the check synchronising relay output contacts have closed, confirming that the synchronising conditions are correct. The guard relay prevents the circuit-breaker being closed by premature operation of the discrepancy control switch. Selection of either 'peak' or 'standby' energises a relay which connects the auxiliary power supply to the automatic synchronising relay. When the gas turbine is running up in speed, a further relay energises which
connects both the running voltage and the incoming voltage to the automatic synchronising relay, causing the synchronising operation to begin. Circuit-breaker closure disconnects both the running and incoming voltage from the automatic synchronising relay. 4.2.3 3.3 kV and 11 kV distribution switchgear
Manual synchronising facilities only are available at the electrical auxiliaries control panel. The operation commences with plug connection of the synchronising trolley to the appropriate circuit, which connects the auxiliary power supply to the check synchronising relay. With 'check operative' selected and the 3.3 kV or 11 kV circuit-breaker open (to connect running voltage) both the running voltage and incoming voltage are connected to the synchronising equipment. Voltage controls are not provided since with normal voltage regulation the voltage difference should be slight. The 3.3 kV or 11 kV circuit-breaker is closed by operating the discrepancy control switch, initiation being permitted by the check synchronising relay and guard relay if synchronising conditions are correct. Manual switching with 'check inoperative' selected is normally restricted to closing the circuit-breaker onto a dead busbar. The above also applies to manual synchronising in switchrooms or other plant locations, if this facility is installed, except that switch closing is initiated by operating the local 'open/neutral/close' control switch.
Synchronising equipment roor facilities are otherwise used for closing onto a busbar. 4
3.3 kV diesel generators synchronising schemes referred to in too recen( this chapter (scheme (a) and scheme ,., ; „ [I 4.1 o f
2. 4 I L
..„2
i
re desci ibed in the following paragraphs.
s,,,, tque (a) inual and automatic facilities are available at the N. auxiliaries control panel after the selection [remote' at the local control panel. The 3.3 kV diesel .:,:nerator synchronising trolley is used for synchro,i n g, Both manual and automatic synchronising operations begin after the diesel generator has been ,[arted and run-up under the supervision of the autocontrol system, and commence with • ane sequence of the synchronising plug into the apo le insertion ni
propriate circuit socket. For manual synchronising, 'check operative' is se1,:cied at the control selector switch on the synchronism , trolley which connects the incoming and running whage to the synchronising equipment. Voltage and speed control are by adjustment of the automatic volt2e regulator and speed governor controller, respectiveClosure of the 3.3 kV diesel generator circuitbreaker is achieved in the same manner as previously described. Manual synchronising with check inoperative is again normally used for closing onto a dead circuit, as happens following the loss of external supplies. Nloving the control selector switch to the 'automatic -,richronising' position connects the incoming and running voltage to the relay. With the equipment prepared, manual operation of the 'auto synch initiate' pushbutton on the synchronising trolley prepares the DC output circuits which control the voltage, speed and circuit-breaker closing.
on castors for ease of mobility. The housing is a sheet steel fabrication which matches the design of the control desk in profile and colour. The trolley contains two sets of instruments, one for synchronising 3.3/11 kV circuits and the other for synchronising generator/grid voltage circuits. The check synchronising relay, guard relay and interposing transformers for synchronising 3.3/11 kV circuits only are internally mounted. Accommodation for the two flexible trailing cables is located on either side of the trolley. Each cable is for one set of synchronising instruments and is approximately 3 m long. An approved design of synchronising plug terminates the free cable end. This, as described earlier, fits into mating sockets mounted on the mimic panels and control desk. The plug contains male pins and the sockets have shrouded female connectors. Parking sockets on the trolley locate the plugs when not in use. When viewed from the front, the 3.3/11 kV instruments are located on the left hand side and the generator/grid voltage instruments are located on the right hand side of the trolley. The voltmeters, phase angle voltmeters and synchroscopes are mounted on the steeply inclined front face and the selector switches and 'synchroniser locked out' indicator are mounted below on the slightly inclined desk top. Centrally mounted on the desk is a four-position system voltage switch, for the selection of the various manual synchronising facilities. The four control selector switch positions are: 1 3.3/11 kV, check inoperative 2 3.3/11 kV, check operative 3 Off 4 Generator/transmission voltage (e.g., 23.5/400 kV) The synchronising instruments provided for duties associated with selector switch positions 1 and 2 are:
Scheme (b)
• Running voltmeter
Only automatic synchronising facilities are available in he central control room at the electrical auxiliaries control panel after the selection of remote at the local control panel. This removes the need for the additional 3.3 kV diesel generator synchronising trolleys in the central control room. Synchronising is achieved, as before, by depressing the 'auto synch initiate' pushbutton located on the control panel. Automatic and manual synchronising facilities are available at the local control panel, the synchronising operation being as already described.
• Incoming voltmeter
5 Synchronising equipment
• Phase angle voltmeter • Synchroscope • Phase angle voltmeter switch (black scale/red scale/off) • Slip feature switch (in/out) • Synchroscope switch (on/off) • 'Synchroniser locked out' indicator The synchronising instruments provided for duties associated with selector switch position 4 are: • Running voltmeter
5,1 Synchronising trolley Figure 12.9 shows a typical control room synchronising trolley which is a compact floor-standing unit mounted
• Incoming voltmeter • Phase angle voltmeter • Synchroscope 963
Synchronising
Chapter 12
MANuAL SYNCHRONISING TROLLEY INCOMING VOLTS
IN
•
21 5K
PHASE ANGLE AOLTME'ER
SYNC HROSCC)PE
S,. P FEATeRE SWV:H •1 N OUT,
SYNCHROSCOPE ON OFF!
PHASE ANGLE VOLTMETER SWITCH BLACK RED OFF : SYNC HRONiSEP ,OCKED OUT INDICATOR
SYSTEM VOLTAGE SWITCH
FIG. 12.9 Control roor - ynehronising trolley
• Phase angle voltmeter switch (black scale/red scale/off) • Synchroseope switch (on/off) The incoming and running voltmeters are of the same size and have the same scales. The scale shapes are 964
,ubstantialty linear and match to within 2 ° at all major marks on the scale. The phase angle voltmeters are the same size as the incoming and running voltmeters and the synchroscopes are of the same type and make. The two scales marked on the voltmeter and phase angle voltmeter, the maximum number permitted on an instrument, are marked in different colours for clarity.
Synchronising equipment e scale is in black and the other red against a white o n ba,:karound. Since there are two sets of numbers and se instruments should only be read at a t he hori distance. The selector switches are mounted with ' r the 'off' or out positions at the 12 o'clock ., r h e except for the phase angle voltmeter switches his is the 'black' scale position. This switch ! , ,, cre t ..prina-loaded to return automatically to the 'black' positions from the 'red' scale position, when reA notice is displayed adjacent to the switch arn that the phase angle voltmeter switch has to returned to the 'off' position before synchronising, not a rotating instrument. Each synchronising a , it is irotrument has a clear external label. When separate nehronising trolleys are provided for synchronising ..,, 1.1 kV diesel generators, the automatic synchronising iay is housed inside the trolley with the other manual rc ,%nehronising equipment. A different size of synchro,,.ing plug is fitted to prevent incorrect use. The n .‘riehronising instruments are centrally mounted and 1 [e synchronising control selector switch has the followpositions: -
ii
I \Amnia] synchronising, check inoperative ' %lanual synchronising, check operative 3 oil 4 Automatic synchronising
\uto synch complete' and 'Auto synch locked out' Lalicators are mounted with the synchronising controls. 5.1.1
Voltmeters
Each voltmeter is a part-circular scale instrument of he rectifier moving coil type. The resistance of the :fl ,,[rument is not less than 1000 WV. The red outer ,:ale reads the higher of the two system voltages and ,ale numbers are limited to three digits. The pair of ohmeters scaled for use with the electrical auxiliaries s: iem are calibrated to display 3.3 kV and 11 kV at 63.5 V input. The black inner scale extends from 2.1 kV !i) 4.2 kV and the outer red scale from 7 kV to 14 kV. [he pair of voltmeters, calibrated for use with gen.:raior voltage and transmission voltage circuits, tYPi -Illy display 23.5 kV and 396 kV (for 400 kV system oltag.e) at 63.5 V input. The inner black scale extends 'rom 14.2 kV to 28.4 kV and the outer red scale from 40 kV to 480 kV.
RMS volts. With the two voltages equal, 1% = 0.6 ° (elec). The instrument is a more accurate means of measuring the phase angle for system synchronising than the synchroscope, which is not calibrated in degrees and therefore only provides an indication of this value. The phase angle voltmeter specification is the same as that for the incoming and running voltmeters except for the voltage range and scales. The inner black scale reads 0-240% and is used initially, subsequently switching to the outer red scale (which reads 0-60%) for more accurate measurement, the scale interval being 20% for the black and 5 07o for the red scales respectively. Both scales have 12 corresponding divisions. The 0, 80%, 160% and 240% positions on the black scale and the 0, 20%, 40% and 60 07o positions on the red scale are major marks and all other scale marks are minor marks. The instrument is calibrated so that the black 240% is displayed for an input of 152.5 V AC and the red 60%, for an input of 38.1 V AC. An external range change resistor is used to change the scales. A typical instrument dial face is shown in Fig 12.10. 5.1.3 Synchroscope
The synchroscope is the principal instrument for manual synchronising. This is a two-winding instrument which, when connected between two supplies, is in effect a two-phase motor with a pointer fixed to its rotor. When revolving, the pointer indicates the slip frequency and when it is moving slowly or is stationary, indicates the phase angle between the voltages applied to the two windings. The synchroscnpe, therefore, not only gives a positive indication of the instant
5.1.2 Phase angle voltmeters Phase angle voltmeters work on the principle that, if ,i1Q incoming and running supply voltages are equal, he phasor difference voltage is a measure of the phase 4 n.g1e. With the instrument connected across the two 'uPplies, the same reading is indicated for a given Phase angle irrespective of whether the incoming volt-ige is in advance of the running voltage or vice versa. rhe scale is calibrated in 07o of single-phase-neutral
FIG. 12.10 Phase angle voltmeter dial face 965
Synchronising to close the switch, but also indicates any adjustments that need to be made to the speed governor set point to reduce the frequency difference. Zero phase displacement and slip frequency are indicated when the pointer coincides with the synchronising mark at the 12 o'clock position and is stationary. If the two frequencies are exactly equal but have a phase displacement, the pointer assumes a position with respect to the synchronising mark corresponding to the phase angle. If the frequencies are different, the speed of rotation of the pointer corresponds to the slip frequency, i.e., the slower the pointer revolves, the smaller the frequency difference. When moving slowly, the phase angle is likewise indicated between the position of the pointer and the synchronising mark. The direction of pointer rotation indicates which of the two frequencies is higher. This is clockwise if the incoming frequency is higher, indicated by an arrow and the word 'fast' or a sign, and anticlockwise if the incoming frequency is slower, indicated by an arrow and the word 'slow' or a ' sign. Indications are displayed at the right and left upper quadrants of the dial face (Fig 12.11). Synchroscopes typically operate over the frequency range 47-51 Hz and have an accuracy for practical purposes of +2 ° (elec) When not in use, or with one circuit de-energised, the pointer is biased away from the synchronising mark by an angle exceeding 45 ° . The synchroscope is normally brought into service when the two voltages have been equalised and the frequency difference is s 1.5 Hz to ensure that the pointer starts to rotate in the correct direction. When manually synchronising a steam turbine-generator, the speed gov-
FiG. 12.11 Synchroscope dial face 966
Chapter 12 ernor set point is adjusted until the synchroscope pointer is moving slowly or creeping in the 'fast' (clockwise) direction at, say, 30 ° (elec) per second. Switch closure is initiated with the pointer on the 'slow' side of the instrument at the moment the correct advance angle in front of the synchronising mark is reached. For a switch with a closing time of, say, 300 ms, the correct advance angle would be about 90 (elec). While the angle is indicated by the synchroscope pointer, the dial face is not calibrated and therefore the phase angle must be estimated.
5.2 Guard relay The function of a guard relay, as described earlier, is to ensure that the operator follows the correct synchronising procedure by preventing operation of the switch closing circuit if the 'close' signal is initiated prior to the check synchronising relay, indicating that conclitions are satisfactory for synchronising. There are a number of ways this control feature can be incorporated into the closing circuit logic and a detailed description of guard relay operation as employed by the CEGB is given in Section 7 of this chapter. En brief, the guard relay has two coils, both of which control relay operation. At 3.3/11 kV, only one coil is energised and this operates the relay allowing closing circuit operation if the close signal is correctly initiated. However, if the close signal is prematurely initiated, this energises the second relay coil which de-energises the relay thus preventing closing circuit operation. This also causes the 'synchroniser locked out' indication to be displayed on the synchronising trolley. The control selector switch must be switched to the 'off' position to reset the relay. 5.3 Check synchronising relay This, as mentioned earlier, is a device for checking that the voltage, phase and, when required, slip frequency of the two supplies being manually synchronised are within preset limits. Figure 12.12 shows a typical check synchronising relay. The relay is connected into the switch closing circuit in series with the discrepancy control switch. Initiation of switch closure via the interposing relay is permitted by the check synchronising relay output contacts if the above measurements are within preset limits, otherwise the closing signal is inhibited. Check synchronising relays have been available for many years. Following various stages of development, in which electronic circuitry superseded electromechanical means, present day units are compact static devices (except for the output relay) and are virtually maintenance free. Several types of relay are available, offering one or more measuring functions. All include phase measurement, with the addition of slip frequency and voltage measurements, if required by the user. The CEGB specifies a unit having all three functions, with
Synchronising equipment
SKD SK D 11 xX 1 C No 1,1 90 - 59N
K1
3
90
1 3
675
23
85
40
625
52
80
66
/ 9 20'
V n 63 5 110V
FRAY WORTHS INTERNALLY BEFORE HANDLING
Vx
Isom
°=I
EXT. — n
t
0
50Hz
50 v=
2 sec
K2 27
3
53
4
66
5
74
6
8.0
10
91
Flo. 12.12 Typical check synchronising relay . , :crnai connections to by-pass slip frequency mea-
..7mient for generator synchronising. The slip feature, Liter described, is only intended for the measure%: n«)t- the small slip frequencies associated with sys•.:n nchronising. Undervoltage is the only voltage , ii dirion specified to prevent closing. As a precaution malfunction, electrical isolation is required "%!%%,:en both AC inputs, the DC power supply inlt and the output terminals. Isolating transformers normally fitted at the AC input and an electrohanical relay indicates the check synchronising reoutput. The relay contacts must be capable of the load of the interposing relay over a of two thousand operations. A simplified ".OA diagram of a check synchronising relay is shown :1 Fig 12.13. ..
53,1 (
)ne of
Phase measurement
the simplest ways of determining phase angle to compare the voltage envelope produced by the mdulated beat waveform with a DC reference voltage 11 2 12 .14 (a)).
A permissive output is obtained when the voltage waveform is less than the DC reference. The phase setting is determined by the magnitude of the DC reference. The intersection between the two voltages is symmetrical about the phase coincident position. The actual angle over which synchronising can occur is therefore twice the setting value 61, extending from where one voltage is the setting value in advance of the other to the setting value where the voltage positions are reversed. The effect of minor variations in supply voltage may be almost eliminated by arranging that the DC reference is proportional to the scalar sum of the two supplies. Performance is further improved if the voltage envelope is full wave rectified. This assists the smoothing by effectively doubling the high frequency component as shown in Fig 12.14 (b). A phase angle setting of 20 ° (elec) is used for all power station applications and also normally at trans° ° mission stations. A setting accuracy of —2 +0 (elec) is specified, although better than this is normally obtained. The total variation from the actual setting under all combinations of specified variations in AC 967
Synchronising
Chapter 12
ADO
V VOLTAGE
DETEC TOR
D.0 REFERENCE VOLTAGE
COF.IPARA TOR AND INTEGRATING AMPLIFIER
INTERPOSING TRANSFORMERS
K1
LINK TO INCLUDE TIMER
®
VOLTAGE LOCK OUT
6-0 OUTPUT RELAY
STABILISED POWER SUPPLY TO ALL MODULES
OUTPUT CONTACTS (S-0
18V 0 C
FIG.
12.13 Simplified block diagram of a typical check synchronising relay
DC REFERENCE LEVEL
1
-4- 0
---
0-1-41-
allow the permitted closing angle to exceed the phase angle setting. 5.3.2 Slip frequency measurement
PHASE COINCIDENCE
(a) Modulated beat waveform
DC REFERENCE LEVEL -s 1 -4--
-11.1
rrrl. (b) Full wave rectified modOatdd beat waveform
FIG. 12.14
Phase measurenient
synchronising supplies, DC power supply and ambient temperature must not exceed ±2 ° (elec) and must not 968
Slip frequency can be measured by determining the phase angle traversed in a defined period. If the phase angle is already measured as described, the slip measurement can be readily obtained by arranging for the output to drive an accurately calibrated timer. With this method of slip measurement, it is convenient to present slip settings in terms of time. The relationship between timer setting (t), phase angle setting (0) and slip frequency (f 5 ) is t = (0/180)/f 1 seconds. For example, with a phase setting of 20 0 (elec) and a slip frequency limit of 0.028 Hz (10 ° (elec)/s) this gives a timer setting of 4 s. The limitation with this method of slip measurement is that time is taken to measure the slip frequency when the phase is within the phase angle setting. Therefore this method of slip measurement is only suitable for the measurement of small slip frequencies. For example, with a slip setting of 2 seconds (0.055 Hz) ° and slip frequency of 0.04 Hz, an angle of approx 29 (elec) is traversed before synchronising is permitted, as shown in Fig 12.15.
Synchronising equipment mum acceptable value. With slip measurement as described, this time delay is automatically provided by the slip measurement timer; otherwise, a separate timer is incorporated, having an accuracy better than +20% — 0%. This timer is also by-passed for generator
PHASE COINCIDENCE
synchronising . 5.3.3 Voltage measurement rBTE0 OVER ELEC) ANGLE
SYNCHRONISING PERMITTED OVER 11 (ELEC) ANGLE
PHASE ANGLE SETTING 20= (ELEC) FIG. 12.15 Limitation of slip frequency measurement
Besides resulting in a sizeable phase error, the time ailable for initiating switch closure is less than one ,2s:ond (as indicated to the operator by the 'check s\r nch monitor' lamp, where fitted). This period is llikely to be adequate for the operator to respond ncl therefore this method of slip measurement is un, suitable for generator synchronising with load pick-up. The switch closing time has to be considered when ,electing the slip frequency setting. If switch closure initiated when the phase displacement is increasing at a position corresponding to the phase angle setting, tile phase error will be greater than this value by an 'mount equal to the advance angle when the switch :/lain contacts close. The maximum acceptable slip for I
,s[em synchronising is 0.055 Hz (20 0 (elec)/s). Using rIlls value as an example, with a switch closing time DI 300 ms the cumulative phase error under these ,anditions (with a phase setting of 20 ° (elec)) is 26 ° [elec). To reduce this additional error, a requirement tas been introduced that the ti me taken to traverse the phase angle setting must he greater than 10 times the ,citch closing time or 2 seconds, whichever is the , :reater. Therefore, in the example above with a switch dosing ti me of 300 ms, the minimum timer setting is = seconds. This setting corresponds to a maximum frequency limit of 0.037 Hz (13 ° (elec)/s) and the amulative phase error is reduced to approximately 24 ° (dee). To span the range of switch closing times, adjust-
able timer settings between 2 seconds (0.055 Hz) and lO . seconds . (Q.011 Hz) are specified. These settings are adjustable either continuously or in one second stages !ID 6 seconds (0.018 Hz) with no intermediate steps !lien before the 10 seconds (0.011 Hz) setting. Accu. 'leY of slip measurement is better than +5%. There is a further requirement that at least 2 seconds must elapse between the application of the 'incoming' and 'running' supplies to the relay and an output be. ng given. This ensures that slip frequency is correctly Fil easured, particularly if it is greater than the maxi-
The undervoltage check facility inhibits synchronising if either the incoming or the running voltage is less than a preset percentage of nominal voltage. Accurate voltage measurements can be made by separately comparing the two voltage inputs, after being rectified and smoothed, with a stabilised DC reference voltage
obtained from the relay power supply. The magnitude of this reference represents the nominal system voltage. Voltage settings are adjustable either continuously or in 2.5% steps over the range 80-90% of nominal system voltage. For steam turbine-driven generators, the normal setting is 85% and for all other applications, including transmission stations, the normal setting is 80 070. Using the above methods of measurement, check synchronising relay operation can now be described. On being switched into service, the incoming and running voltages are measured and, assuming that both are greater than the preset percentage limit of nominal system voltage, an output initiated by the phase measurement circuit starts the slip frequency timer when the phase is less than the phase angle setting, i.e., the voltage waveform is less than the DC reference. The timer energises the output relay on completion of its timing cycle provided the output from the phase measurement circuit persists, i.e., the voltage waveform has remained less than the DC reference. Energising the output relay signals permission to close the switch. 5.4 Automatic synchronising relay Automatic synchronising relays monitor the voltages and frequencies of the incoming and running supplies and give out signals which are used to control the incoming voltage (or running voltage) and the incoming frequency. The relay senses voltage and frequency differences. On detecting differences the matching circuits signal corrections, the voltage corrections being signalled either prior to or simultaneously with frequency corrections. Once preset conditions are obtained, a pulse signal is sent out to energise the interposing relay which, in turn, closes the switch. Early designs were electromechanical devices; one example used electromagnets and springs similar to a wattmetric element to produce restraining and operating torques in an aluminium disc. When the operating torque was applied for a sufficiently long period, this gradually wound-up a thread around a grooved pulley against the force of the spring until, eventually, the relay contacts closed when the voltages were equal and 969
Synchronising
Chapter 12
phase coincided. Development progressed with the growing need for a higher degree of precision and reliability resulting from the increase in size of generators being installed and the increasing trend towards automation of power stations. This improvement continued with the introduction of static circuitry until, with present day relays, models with multifunction specifications capable of operating over a wide voltage, frequency and ',lip frequency range are available to suit most user needs.
CT'
14 (7) 0 0 * 0
ASYNCHRONOUS -DETECTOR
VOLTAGE 7ETECTOR
.0
FREQUENCY DETECTOR
0
Figures 12.16 and 12.17 show a typical automatic synchronising relay and its associated simplified block diagram respectively. The relay is designed to fail safe and duplication of circuitry is extensively employed in order that component failure is promptly detected. The malfunction of any component prevents closure of the switch and results in lockout of the synchroniser. Lockout is an inhibit which, once initiated, remains operative until the synchroniser is switched off. Other lockout features
0 C0
0 *
tm ...,
.0 C
rm
RELAY UNIT
LOGIC
POWER SUPPLY
OUTPUT SIGNALS
SE T mAx•Mum SUP
a
MISMATCH
SET GOvERNOR puLSE WIDTH
PERCENT
SET PAUSE TIME
0 P T
0
•2
4
RAISE # •-tOLTAGE LOWER .--... 411/ yei SEQUENCE COMPLETE OR UNIT FAULTY
SET VOLTAGE
-NC.T.'!.oi NG L. iE
RUNNING L vE
*
0
—
2 —• SECONDS PER CYCLE
RAISE # # INITIATE FREQUENCY .„ SPEAKER , ,,„ c ..._.. CLOSURE ----- 9)
40.1%1L AR ,
0 -. , 5V
Dv
- - SX
FIG. 12.16 Automatic synchronising relay
SYNCHRONISES LOCKOUT' IN VOLTAGE MATCHING UNIT EXTERNAL AOJUSTMENT FOR VOLTAGE ERROR LIMIT ANO LOW VOLTAGE LOCK-OUT
LOW VOLTAGE MONITOR V<
RAISE VOLTAGE 1 ,NTERLOCKE0 GP :NHL- LASoNT, C;OE J R
V
TAP LOWER VOLTAGE
NPUT RANSFORMER
NCCIAING SUPPLY Qu.N.NING
—
SvPPLY
FREQUENCY MATCHING UNIT EXTERNAL ADJUSTMENT FOR PULSE SIGNAL TO SUIT GOVERNOR CHARACTERISTICS
— RAISE SPEED
1LIRGE SIGNAL OR LOW SLIP LOCK-OUT)
' :NTERLOCKED SIGNALS TO PRIME MOVER SPEED GOvEFINCR
LOGIC UNIT ,I NCLUDING OUTPUT RELAYSI '-----LOWEP SPEED
–CLOSE t
POWER
St1 P PLY
UNIT
DUPLICATE SIGNALS TO INTERPOSING RELAY
ASYNCHRONOUS PHASE OETECTING UNIT AL ADJUSTMENT FOR SWITCH CLOSING TIME AND MAXIMUM SUP FREQUENCY
CLOSE
SYNCHRONISING COMPLETE' INDICATION
FIG. 12.17 Simplified block diagram of a typical automatic synchronising relay
970
-
111111111■Synchronising equipment the incoming /running voltage or a minimum value. The voltage 1, also used to monitor the auxiliary DC oRage. :irk: provided to prevent signals to %oltage or frequency being dispatched
:I ii tshebrelow
.
_•„ (: ••1:•• •
v.hich the two voltages are matched adjustments covering the range 0 ing voltage typically being provided. or runn flLe required on setting is ± In of nominal . ,ilthough better than this can be obtained. 01 error setting is normally 4 0 (nominal). tiired synchronising method is selected by r c\ternal control options. To synchronise supero ously, a continuous 'raise' signal to drive the ..• ori e synchronous rapidly, followed by pulsed to control the speed for synchronising, o he governor, To synchronise sub-synchrot ‘.. ontinuous lower' signal (if necessary) and • , .„1 •rai e' signals are sent to the governor. Figure ,1 10 ,As the two control signals to the speed .
' , ti kes, a maximum of one per slip cycle, are sent 0 he 180 point on the beat waveform. maximum slip frequency at which synchro,:an be carried out is adjustable, typical settings 6, 8, 12 and 20 seconds per slip cycle being bic (with an accuracy of ± 10 070). The slip fre,•,:%, .etting is determined by the unit synchronising •r;: ments. 180:
'30
If the slip frequency should become too slow or a point is reached where the two supplies have identical frequencies at a phase angle unacceptable for synchronising, the frequency matching circuit would give no further output signal unless one of the frequencies drifted. To overcome this problem, an urge circuit is incorporated which sends a signal to the prime-mover speed governor if a fixed time has elapsed, typically 20 seconds, since the last 'raise' or 'lower' instruction. The urge circuit sends a pulse in the same sense as the previous pulse. With steam turbine-generators, this signal is adapted into a minimum slip frequency setting to prevent motoring. This is called low slip lockout' and is a fixed setting. A typical value is 14 seconds per slip cycle. To synchronise a steam turbine-generator super-synchronously, one speed control pulse must not produce a frequency change or slip bandwidth (l c ) greater than the difference between the maximum slip frequency (fsmax) and the minimum slip frequency 0 - If the governor rate with a continuous pulse is a g , then the pulse width selected must be less than t_i max = /a g seconds.
Example A steam turbine-generator is required to be automatically synchronised with approximately 5 11 0 load pick-up and a low slip lockout of 14 s/slip cycle. With a governor rate of 0.05 Hz/s and speed droop of 4%, determine the maximum slip setting and the maximum governor pulse width. The maximum slip settings available are 4, 6, 8, 12 and 20 s/slip cycle. fsmax
4
5 ——x 100
x 50 — 0.1 Hz
100
0.1 Hz = 10 s/slip cycle BEAT WAVEFORM
If the maximum slip setting of 8 s/slip cycle is selected from the range of settings available, the maximum slip frequency is 0.125 Hz
„ -MN ■•■•••
PULSE CYCLE fsmLn
=
= 0.071 Hz 14
PULSE SIGNAL
so, f e = 0.125 — 0.071 = 0.054 Hz The governor pulse width must be less than 0.054
CONTINUOUS SIGNAL
0TH =-= WIDTH LSE CYCLE
NOT TO SCALE
FIG. 12. 18 Governor signals
tlmax
—
1.08 s
0.05 The signal pulse width is adjustable to cater for a variety of governor rates, typically 0.1 to 2.0 s. The recommended setting would be 0.8 times the maximum pulse width, i.e., 0.86 s in this example. Figure 12.19 shows an example of the modulated beat waveform and governor pulse signals during synchronising under the above conditions. 971
Synchronising
Chapter 12 ,
(0)2) 2 = (. i) 2 f a 165HZ , .41—)4.-'
= 0 125Hz
rearranging
= 0 082Hz
114=H4K
2lice
(w2) 2 - (.1) 2
, 1
/
--
ff
\
/ 1
..."
--•••
...
.,-III il r 71 • r
. . .-
--.. .
.1".• - -
•••.., -.•• •
11 .._.11 .
,
. ._. . _-
ANC. 1.7 O
'80
,.....
n! 1
---
2ce
ii
where a = angle of rotation, radians w = initial angular velocity, radians/s
4
us2
CHANCE r0 SYNCHRONISE
S +54CPRONISE
' 90
1. 1 i'rrn
—
•IF FIRST CHANCE MISSED)
1
180
80
final angular velocity, radians/s angular acceleration, radians/s 2
now
angular acceleration
angular velocity :'41--1."1 O86
086s
0 85s
Flu. 12.19
0 865
Beat waveform and governor pulse signals during synchronising
The number of possible chances to close the switch within the slip bandwidth can also be specified, although this is normally not done by the CEGB. If it is specified, one speed control pulse must not produce a frequency change greater than:
therefore, converting the equation to frequency: Rate of change of frequency = — ( f 22 — 1. 21 ) The maximum allowable rate of change in frequency is brought about by a deceleration of the rotating shaft from the maximum to the minimum slip frequency setting over one beat cycle, i.e., a = 27r. This is also the maximum allowable governor rate if the two are to remain in step. Therefore:
slip bandwidth
f an
a gmax
(fsmax) 2
where f smax = f1 Example
A pumped-storage generator is to be synchronised sub-synchronously in the generating mode when a slip frequency of 1 07o is attained. If the required number of chances to close is 3 and the governor rate is 0.4 Hz/s, determine the maximum pulse width. Slip bandwidth = 50 x 1 07o = 0.5 Hz =
0.5
Maximum pulse width ti ma,,
this is a deceleration)
A governor rate less than the maximum allowable is recommended, i.e., recommended governor rate = 0.8 x maximum allowable governor rate. With pulsed signals, the governor rate is reduced in proportion to the ratio of pulse width to pulse cycle. i.e., actual governor rate =
fen/a g = 0:17/0.4
governor rate x
With large steam turbine-generators, the high inertia prevents the speed falling quickly and therefore the minimum pause width, i.e., time between successive 'lower' pulses, is increased (instead of every beat cycle) to prevent a large discrepancy arising between the actual turbine-generator shaft speed and the governor set point. The equation for rotational motion with a constant angular acceleration is given by: 972
fsmin = f2
(neglecting the negative sign as
= 0.17 Hz
= 0.425 s
(fsmin) 2
2
number of chances . to close switch
fen
– frequency
27r
II 33s
7 145
509s
rate of change of frequency
2r
pulse width pulse cycle
In this case, the actual governor rate is the recommended governor rate. The minimum pause width can be calculated using the above equations. A typical automatic synchroniser has adjustable pause widths between 0.5 to 10 s. Example
A 660 MW steam turbine-generator has a governor rate of 0.1 Hz/s. The maximum slip setting is 8 s/slip cycle with a low slip lockout of 14 s/slip cycle. With a pulse width of 0.2 s, determine the minimum pause width setting.
Synchronising equipment if
a gmax
) 2 — (fsmin) 2
2 2
(0.125) - (0.071) 2 2
matic sequence control system. At a suitable point, the automatic voltage regulator is switched in to establish open-circuit voltage and control of voltage (running) and speed is passed to the automatic synchroniser. Automatic synchronisation is required to be achieved super synchronously within the following operational li mits:
= 0.005 Hz/s Recommended = 0.8 x 0.005 = 0.004 Hz/s governor rate Pulse cycle
= pulse width x governor rate recommended governor rate = 0.2 x 0.1/0.004 = 5 s
Minimum pause width
= pulse cycle - pulse width = 5 - 0.2 = 4.8 s
The switch close signal must only be sent out when both supplies are within the specified limits. The phase angle sensing elements, which initiate switch closure, are therefore duplicated and the output contacts are connected in the positive and negative sides of the interposing relay. The required duration of the closing pulse is for a period of -t 0.55 s and /. 1.0 s and is typically set at 0.75 s. The output contacts are rated to switch the load of the interposing relay and its associated wiring over many operations. The relay is a single-shot device and therefore both elements must signal in step, otherwise lockout facilities are initiated which remain operative until re-primed. The relay can only be reprimed by being switched off. This occurs automatically after successful operation of the relay. The relay is set to the closest available setting to the measured switch closing time during commissioning. A range of steps with 25 ms intervals between 50 ms and 500 ms is typically provided. In this respect, it is important that the switch closing times are consistent if the relay is to remain correctly matched. Under these conditions, accuracy of synchronising with a phase error less than 8 ° (elec) is specified. However, better performance with a phase error less than 5 ° (elec) is normally obtained. After synchronisation, the incoming and running voltages are disconnected and remote indications are given out that synchronising is complete and that the synchroniser is locked out. 5.41 Steam turbine generator synchronising -
Automatic synchronising relays for steam turbine-generators can be used for synchronising across generator voltage or transmission voltage circuit-breakers. Steam turbine-generators are run-up and operated either manually or under the supervision of an auto-
Frequency range
47-51 Hz
in any
Voltage range
85-115o (nominal)
combination
Voltage error setting
4 01D (nominal)
Maximum slip setting
0.2% above synchronous
Phase error
8 ° (elec)
Load pick-up
l -5 07o full-load
The voltage difference across the circuit-breaker is reduced in steps by operation of the generator transformer on-load tapchanger until voltage matching better than 4 07o error setting is attained. With an initial speed of between 46.5 Hz ( - 7%) and 51.5 Hz ( + 3 010, the governor set point is adjusted to cause the unit to approach synchronous speed from a higher speed. The action continues until the speed has fallen below the maximum slip setting of 0.2%. With a speed droop of 4 07o, this corresponds to a load pick-up within 1-5 010 of full-load. Provided these conditions do not change, the phase angle sensing elements at the first chance initiate the closing of the switch at a point which will result in the main contacts closing with a phase error less than 8 ° (elec). Lockout facilities operate if: • Either incoming or running voltage drops below 85 0/o of nominal. • The steam turbine-generator speed is no longer fast, i.e., a low slip condition which could result in the generator motoring. • Component failure occurs. • Synchronising is complete. Indications of 'synchronising complete' or 'synchroniser locked out' inform the operator of the end result. A buzzer also sounds when the switch has closed. 5.4.2 Gas turbine generator synchronising -
Gas-turbine generators are run-up and operated under the supervision of the automatic sequence control system. The synchronising operation forms part of this control sequence and the synchronising unit is automatically switched in at a speed which will ensure that synchronising can take place at the minimum specified system frequency, while permitting the speed to be adjusted as rapidly as the machine and control characteristics permit. Having taken control of voltage and speed, the automatic synchroniser is required to achieve synchronisation within the following operational limits: 973
Synchronising
Chapter 12
Frequency range
-10-5l Hz
Maximum slip setting
0.2%
Voltage range
80-115 070 (nominal) } combination
Phase angle error
8 ° (dee) normal, 16 (elec) permissible
Frequency fall
1 Hz every 25 s
Load pick-up
1 -5% full-load
in any
Voltage fall
1.5% (nominal) every 25 s
Voitatre error setting
4% (nominal)
Maximum ,Eip
1 % below s!,nchronous (unless otherwise specified)
l'ha:c error
8 (elect normal, 16 ° (elec.) permissible
Speed adjustment continues sub-synchronously until the maximum slip setting of 107 0 is reached, while the voltage is regulated by adjustment of the automatic voltage regulator for emergency gas turbines (incoming) or by adjustment of the generator transformer on-load tap-changer (running) for peak lopping gas turbines, until the voltage difference is within the voltage error setting of' 4%. Providing these conditions do not change, the phase angle sensing elements at the first chance initiate the closing of the switch at a point which will result in the main contacts closing with a phase error less than 8 ° (elec). To take account of inherent variations in turbine governor characteristics, which can cause some change of slip at the point of synchronising as well as changes in DC auxiliary supply voltage which can result in a variation in normal switch closing time, a maximum phase error of 16 ° (elec) is permissible. If, for operational reasons, it is required to synchronise the machine with the incoming supply frequency greater than the running supply frequency, then the synchroniser reduces the speed to within the maximum slip setting value and synchronises the unit within the voltage and phase error settings given. Lockout facilities operate if: • Either incoming or running voltage drops below 80 070 of nominal. • Any auxiliary supply is absent. • Component failure occurs. • Synchronising is complete. Indications of 'synchronising complete' and 'synchroniser locked out' or 'synchroniser failed and locked out' inform the operator of the outcome.
0
Speed control is initiated after voltage matching has been achieved. The voltage is regulated by adjustment of the automatic voltage regulator for emergency diesel generators until the voltage difference between the incoming and running voltage is within the voltage error setting of 4%. From an initial speed of between 46.5 Hz ( 7%) and 51.5 Hz (± 3%), the governor set point is adjusted to cause the unit to approach synchronous speed from a higher speed. This action continues, making further adjustments to voltage, if necessary, until the speed has fallen just below the maximum slip setting of 0.2%. With a speed droop of 4%, this corresponds to a load pick-up within 5 1170 of full-load. Provided these conditions do not change, the phase angle sensing elements at the first chance initiate the closing of the switch at a point which will result in the main contacts closing with a phase error of 8 ° (elec). As for gas turbines, to take account of inherent variations in engine governor characteristics which can cause some change of slip at the point of synchronising, and changes in DC auxiliary supply voltage which can result in a variation in normal switch closing time, a maximum phase error of 16 ° (elec) is permissible. Lockout facilities operate if: • Either incoming or running voltage drops below 85% of nominal. • The diesel generator speed is no longer fast. • Component failure occurs. • Synchronising is complete. Indications of 'auto synch locked out' when a close signal has been given and 'auto synch complete' when the switch has closed, inform the operator of the end results. A buzzer also sounds when the switch has closed.
6 Derivation of synchronising supplies
6.1 Secondary supplies 5.4.3
Diesel generator synchronising
Diesel generators are run-up and operated under the supervision of an automatic sequence control system. The automatic synchroniser is manually or automatically switched-in as part of the control sequence, at a speed at which the synchroniser can take over control of voltage and speed and achieve synchronisation supersynchronously within the following operational limits: Frequency range
47 - 51 Hz
in any
Voltage range
85-115% (nominal)
combination
Voltage error setting
4e7o (nominal)
974
Synchronising is performed with incoming and running supplies which simulate the primary circuit conditions. These are obtained from voltage transformers (VTs) and transferred to the synchronising equipment. Clearly the secondary voltages must be derived in a manner satisfactory for synchronising purposes. This requires consideration of the selection of the supplies that are measured and the degree of accuracy within which measurements are made. The measuring circuits operate at a nominal voltage of 63.5 V AC. The connections between the VTs and synchronising equipment are direct wired (transducers
Derivation of synchronising supplies used at transmission stations controlled by a telecontrol system, however, this is beyond the scope of th i s c hapter). Since this leaves frequency unchanged, only the measurement of voltage and phase needs to be c onsidered. 0%erall measurement to within an accuracy of 2% primary voltage and approximately 2 ° (elec) of phase obtained with correct circuit adjustment under ar e normal system conditions. are
6.2 6.2.1
Selection of voltage transformer supplies Single voltage supply
I is first necessary to consider a distribution switch in he process of being commissioned which is about to be used to system synchronise for the first time. The r unning supply is obtained from a voltage transformer (VT) associated with a switch that has already been c ommissioned with phase connections known to be correct. The running supply can therefore be used as a reference for checking the phase connections of the lacoming supply. Assume that three-phase VTs are available, enabling the voltage magnitude on each phase and the voltage difference across the three pairs of c orresponding phases (i.e., R-R B-B Y-Y) to be rnea)ured at secondary terminals. The number of connection configurations for the incoming supply is six. Only one of these is correct, he other five being obtained by crossing the phases, as tabulated below: Incoming supply phasing (1) (2) (3) (4) (5) (6)
R B Y R B Y
Y R B B Y R
B Y R Y R B
The correct phase connections, as in (1), are confirmed
after the measurement of a voltage of equal magnitude (approximately) on each phase and a voltage difference of zero (approximately) across the three pairs of corresponding phases. In (2) and (3), the phase rotation is correct but the phase relationship is wrong and, in (4) (5) and (6), both the phase rotation and phase relationship are wrong. It can be seen that in addition to voltage magnitude a minimum of two, and preferably three, voltage diflerence measurements are needed to system synchronise correctly. The same applies with generator synchronising, but here it is also possible, though not correct, to synchronise with (2) and (3), the generator phase identification, in effect, being rotated. The purpose of commissioning tests, in part, is to find any errors or mistakes in the design, manufacture
and installation which have escaped earlier detection, although it must be added that many prior steps are taken to check that this does not happen. Once the phasing out procedure described has been properly carried out and the circuit commissioned, it is reasonable to assume that the primary connections and the direction in which prime-movers rotate will remain unchanged. On this basis, synchronising can safely be performed using a single representative voltage supply since, with balanced symmetrical three-phase supplies, the synchronising measurements will be identical for all three phases. To summarise, three-phase VT secondary supplies are needed for commissioning tests to establish that the phase connections are correct. In certain instances, it is necessary for commissioning tests to be carried out using an adjacent circuit three-phase VT if the circuit being commissioned has only a single-phase VT installed. After it has been established that the phase rotation and phase relationships are correct, each threephase system is represented for synchronising purposes by a single supply voltage which may be either a singlephase or line voltage. 6.2.2 Incoming and running voltage
To be able to synchronise using the secondary voltages obtained from the incoming and running VTs, these, as shown in Fig 12.20, must: • Measure the same primary circuit voltage (e.g., red phase or red/yellow line voltage). • Have the same primary/secondary voltage transformation ratios and angular displacements. To meet the second requirement, VTs of the same design and make are usually provided for both incoming and running supplies. To obtain a proper and accurate measurement of the primary voltage, voltage transformers are preferably connected to the busbar immediately adjacent to the switch. This applies at the main generator circuitbreaker and to the incoming supply at a switchboard INCOMING VOLTS ,V V
RUNNING VOLTS :v., V
RE0
V,
ELLOW
RED
V
rELLCW
NOT 70 SCALE
FIG. 12.20 'Incoming' and 'running' secondary supplies
975
Chapter 12
Synchronising where the VT is positioned on the outboard or circuit side of the switch. However, it is not normal practice to obtain the running supply at a switchboard (or transmission substation) by connecting a VT to the
main busbars as it is considered that this would reduce busbar integrity by introducing a potential source of failure. The running supply is therefore obtained from a VT on the outboard side of a switch already connected to the main busbars. Where several VTs may be connected to the main busbar at the same ti me, a voltage selection scheme is provided to choose the running voltage. Voltage selection schemes discriminate in favour of the VT associated with the circuit allocated the highest priority and also prevent the VT secondaries from being paralleled. If the VT associated with the circuit with the highest priority is open, the VT associated with the circuit with second priority is selected, and so on. Main incomers are normally allocated highest priority, followed by interconnectors with generator circuits last. Voltage selection and repeat relays are used to produce the required logic, the scheme being designed to ensure that under all conditions of voltage selection the required voltage accuracy at the synchronising
equipment is still obtained. The different scheme arrangements for a 3.3 kV or II kV switchboard are set out in a series of standardised drawings, a typical example being given in Fig 12.21. This is for a switchboard with three incoming circuits. From examination of the relay logic, it can be seen that VT secondaries are connected to the RYB bus wires in the priority order shown.
6.3 Measurement accuracy 6.3.1
Voltage transformers
Voltage transformers (VTs) are divided into different
classes of accuracy, with specified li mits of percentage voltage ratio error and phase displacement error for a given range of operating conditions. The actual error for a given accuracy class and under normal operating conditions, is determined by the size and power factor of the secondary load or burden. Burden is defined as the value of the impedance of the external secondary circuit, expressed in ohms (or in volt-amperes at rated secondary voltage), at the relevant power factor. Voltage transformers on most circuits are provided for more than one purpose. These include supplies for other voltage measuring and recording instruments, e.g., busbar voltage and system frequency, metering, protection, automatic voltage regulators, etc., as well as for synchronising equipment. The individual burdens may vary over a wide range of volt-amperes and power factors. The VT class of accuracy required is determined by the secondary supply with the highest accuracy requirement. 976
For interchangeability reasons, dual rating VTs are installed for a number of applications, with more than one VT per phase if needed to accommodate the number of supplies required. These combine the different accuracy requirements for metering, measurement, protection, etc., in one VT, the limit of voltage and phase error depending on the size of the output burden and power factor for a given range of primary voltage conditions. The requirements for a dual rated
50/150 VA unit with three limits of accuracy are:
VA rating, power factor and voltage range 0-50 VA/0.8 pf lag
Voltage error, Phase displacement cro minutes +0.2
±10
+1.0
±40
+3.0
+120
0.8-1.2 p.u. rated primary voltage 50-150 VA/0.8 pf lag 0.8-1.2 p.u. rated primary voltage 0-150 VA/0.8 pf lag 0.05-0.8 p.u. rated primary voltage and 1.2-1.9 p.u. rated primary voltage
The different VT secondary supplies are separated or
fused either individually or in small logical groups. This approach is essential with capacitor VIs used at transmission voltages, where it is not always possible to obtain satisfactory discrimination with fuses in series owing to the low short-circuit currents available. The factors which determine the distribution of the supplies are the importance, accuracy, burden requirements and security against protection or equipment failure due to loss of supply. With the exception of 3.3 kV and 11 kV switchgear, the supply distribution arrangements are detailed on standard diagrams. A fused supply is provided for the exclusive use of the synchronising equipment.
6.3.2 Interposing voltage transformers Voltage transformer accuracy is not the only source of secondary voltage error. This also occurs due to lead resistance (see Section 6.3.4 of this chapter). The sum of these two errors in the incoming and running supply will not be the same at the synchronising equipment, particularly if the lengths of the connecting cables and hence lead resistances are significantly different. Clearly it is important for synchronising purposes that the errors in the measured voltages are as small as practicable. However, there is a further reason why this is important should the two supplies become electrically connected. Although the direct interconnection of VT secondaries is not permitted, with preventive steps taken internally and externally to the synehro-
"NI
Ur Derivation of synchronising supplies
2nd PRIORITY
3rd PRIORITY
ist PRIORITY
VOLTAGE TRANSFORMERS
ffl I
I
POS 0
ILOG
RA-3
—1
REIr4
RC-2 L_
J
RELAY RC 2
RED YELLOW BLUE
FiG. 12.21 3.3 kV or 11 kV voltage selection schemes
nising equipment, there remains a small risk that this might occur through a fault or sneak circuit. In this fistance, the transformer with the higher of the two
secondary voltages would contribute to the load of the transformer with the lower secondary voltage in the same way that power transformers share load in 977
Synchronising
Chapter 12
parallel, lithe voltage difference is small, this condition would probably remain undetected during normal service with fuse protection. Complications may arise for protection, metering, etc., which may also involve other circuits. Ti) reduce the voltage error in the incoming and running supply, an interposing voltage transformer (\.\ hich also pro v i des DC electrical isolation) is installed bemeen the \ I ,,e,.ondar, and the synchronising equipment, as shown in Fig 12.22. Tappings are provided to facilitate a certain amount of on-site voltage adjustment. With nominal system voltage, each interposing VT tapping is selected to indicate 63.5 V ± 1% at the synchronising equipment with the switch both open and closed. With a voltage selection scheme this includes each alternative source of running supply. The interposing VTs have a ratio between primary and secondary windings of 110/63.5 V (63.5/63.5 V at transmission voltage) and have a minimum rating of 25 VA with a maximum limit of 50 VA, except at transmission voltage where this is reduced to 36 VA. It is, however, preferred that a single rating is used throughout the synchronising scheme for interchangeability reasons. Voltage adjustment is in steps of 0.5 V over the range 0 to + 5 V above rated secondary voltage. The tappings may be divided between the primary and secondary windings as convenient. The transformers in general comply with BS3941 [2] accuracy Class 1.0; i.e., percentage voltage error ± 1 %, phase displacement +40 minutes, at any voltage between 80% and 120% of rated voltage and with burdens of between 25% and won of rated burden at a power factor of 0.8 lagging, except that the range of voltage error is between 5% and 100% of rated burden at unity pf. To ensure that saturation does not occur during over-voltage conditions, the transformer knee point must not be less than three times the rated voltage. As an additional safety precaution, an earthed electrostatic screen is fitted between the primary and secondary windings. 6.3.3
Burdens
To reduce the loading on the VTs and avoid undue voltage drop in the connecting leads, the synchronising equipment is required to have a low burden or VA rating. At transmission voltage, the total burden im-
NTEPPOS , NG
INTERPOSING VT
Vi.
SYNCHRONISING
EQUIPMENT
MAIN VT
MAIN VT
Etc. 12.22 Simplified arrangement of interposing voltage transformers 978
posed on a main VT by the synchronising equipme nt must not exceed 40 VA (this includes voltage selection scheme relay burdens, etc.). Similarly, other devices connected to the main VT are required to have a low burden, due care being taken to ensure that the rated burden is not exceeded for all conditions of switching. Typical maximum burdens under the worst condition of operation that can be imposed on an interposing VT are given below: Manual synchronising —
Synchronising voltmeter, 0.5 VA
—
Synchronising phase angle voltmeter, 0.5 VA
—
Synchroscope, 5 VA (per supply)
—
Check synchronising relay, 5 VA (Per supply)
Automatic synchronising 1 — Automatic synchronising relay, 5 VA (per supply) The above burdens may be exceeded provided that the total burden from all items remains within the specified maximum.
6.3.4 Lead resistance The principal effect of lead resistance is to reduce the magnitude of the secondary voltage resulting in a voltage error at the synchronising equipment. With a single-phase transformer and a purely resistive burden the voltage drop would be the product of the lead loop resistance and the load current. In reality, it also depends on the power factor of the synchronising equipment burden which introduces a phase as well as a voltage error. The calculation is complicated further when applied to three-phase VTs and threephase groups of single-phase VTs connected in star, as the burden across one pair of phases affects the errors across the other two pairs of phases. Multipair telephone type cable is used to transfer the voltage supplies from the electrical auxiliary switchgear to the control room. To limit the voltage drop produced by this type of cable which, due to its small conductor size, has a relatively high resistance, these circuits operate at the main VT secondary voltage of 110 V AC. A common set of interposing VTs is employed for all circuits which are located inside the synchronising trolley. With generator and transmission voltage switchgear, the interposing VTs are provided for each supply. These are normally housed in cubicles located close to the switchgear or in a protection equipment room. Here, multicore control cable is used which has a lower resistance than multipair cable, the secondary circuits to the control room operating at 63.5 V AC. The maximum lead loop resistance values per kilometer for the two cable types normally concerned are as follows:
Derivation of synchronising supplies .1•••••
\lultipair cable
0.5 mm 2 (1/0,8 mm) — copper conductor
73.4 tl (2000 m at 20 ° C)
\lolticorc control
2,5 mm (7/0.67 mm) — copper conductor
1 5.12 (2000 m at 20 ° C)
2
cable
As an example, consider an interposing VT connected to the synchronising trolley via an 800 m (loop) length multicore cable. The measured output voltage at the transformer secondary terminals is 63.5 V AC with a burden of 12.7 VA at a pf of 0.86 lagging. The percentage voltage measurement error at the synchronising equipment would be as follows (see Fig 12.23):
RL — 1,
15.12 x 800 2000
— 6.04 ft
= 12.7/63.5
o error —
1, RL cos0 Vt
= x 100
0.2 6.04 0.86 63.5
0.2 A
x100
= 1.6% where V z = voltage at interposing transformer secondary terminals V, = voltage at synchronising equipment terminals 1,
= load current
RL = lead resistance Although the voltage drop can be compensated for by adjustment of the interposing VT tap, as already de-
scribed this may introduce other difficulties with voltage selection schemes and where possible unduly long con-
nections are best avoided. In exceptional circumstances it may be necessary to parallel cable cores to reduce the voltage drop. A high lead resistance may also necessitate the fitting of ballast resistors to the synchroscope on/off switch
to compensate for the reduction in circuit burden when the synchroscope is switched off.
6.4 Synchronising supplies 6.4.1 Steam turbine-generator
Transmission voltage switchgear Voltage supplies are obtained from the transmission station. Single-phase VTs are installed, which are normally capacitor VTs as these are more economic than electromagnetic VTs. in accordance with CEGB Standard 99384 [3], present standard designs are to BS3941 and rated at not less than 100 VA with accuracy either Class 1 (voltage error ± 1 07o, phase displacement +40 minutes) or Class 3P (voltage error ±31/4, phase displacement ± 120 minutes) and cover the range of burdens between 0°70 and 100% of rated burden, at a power factor of 0.8 lagging. The incoming and running supplies are derived from the yellow phase to earth primary voltage, in accordance with Engineering Recommendation 515 Part 3 [4]. Generator voltage circuit-breaker
The incoming supply for the generator voltage circuitbreaker is obtained from VTs installed in the main connections on the generator side of the switch. A group of three single-phase units is required since the main connections are phase isolated. The VTs are of the solid insulation type, individually mounted in metalclad enclosures, a set of four being installed on each phase. The VT windings are connected in star-star with both neutrals earthed. The rated line to earth secondary voltage is 110/V3 V. The connection arrangement is in accordance with CEGB Standard 994274 [5]. The transformers comply with ESIStandard 35-5 [6], which generally specifies BS3941 except that the performance and testing requirements extend beyond the current British Standard. The ratings and limits of accuracy are as given in Section 6.3.1 of this chapter. The running supply is obtained from the generator transformer side of the generator voltage circuitbreaker. This may be from transformers of the same design and make installed in a single bank in the main connections, or from an additional winding in the interconnected star transformer used to earth the main connections at this point (see Chapter 3, Section 2.5.5). 6.4.2 11 kV gas turbine generators -
Flo. 12.23 Voltage
drop due to lead resistance
There are two options available for obtaining the incoming supply: to use a VT at the 11 kV switchboard, or to use the gas turbine VTs directly connected to the generator terminals. The former, along with the running supply, is obtained from the 11 kV switchboard as described in Section 6.4.3 of this chapter. The latter are solid insulated single-phase units complying with ESI Standard -35-6 [7] and mounted in metalclad enclo979
Synchronising sures, forming a three-phase-connected bank. The ratings and limits of accuracy are as given in Section 6.3.1 of this chapter, with the connection arrangement in accordance with CEGB Standard 994274.
6.4.3 3.3 kV and 11 kV distribution switchgear Star-star connected VTs are located in the fixed, metal enclosed portion of the switchboard on the outboard or circuit side of each venerator or distribution circuit-breaker. The transformers are of the dry-type design with ratios, ratings and accuracy complying with 1353941. The VTs have a rated line-to-line secondary vol t age of 110 V and a rating of 50 VA, accuracy class 0.2 (voltage error +0.2%, phase displacement +10 minutes) when metering supplies are taken. Otherwise a rating of 200 VA and accuracy class 1.0 (voltage error +1%, phase displacement +40 minutes) is used. Dual rating transformers may be supplied for this purpose. The yellow phase secondary is earthed. This provides two 110 V rated single-phase to earth supplies, connection between red and blue phases not being permitted. The burdens are divided between the two supplies with the red to yellow phase supply always selected for synchronising.
6.4.4 3.3 kV diesel generators The incoming and running supplies are derived from 3.3 kV switchgear voltage transformers as described in Section 6.4.3 of this chapter.
7 Synchronising schemes
Chapter 12 proval, relay manufacturers must demonstrate that the relays comply with the applicable CEGB standards by completing a series of type tests.
7.2 11 kV distribution circuit The procedure for manual synchronising is as follows (refer to Fig 12.24): (a) Connect the synchronising trolley to the distribution switch synchronising circuits by inserting the synchronising plug into the socket provided at the Electrical Auxiliaries Switchgear Control Panel. (b) Select '3.3 kV/11 kV check operative' at the manual synchronising control selector switch on the synchronising trolley. This: • Energises one coil of the OR relay. • Closes the OR contact in the close interposing relay coil circuit which now requires both the discrepancy control switch contact and the SYN contact to close to cause operation. • Closes the OR contact in the GRA coil circuit which now awaits SYN contact to cause operation. (c) Check that the voltage difference and phase angle between the two supplies are satisfactory, using the synchronising trolley instruments. (d) The check synchronising relay confirms that conditions are satisfactory by closing SYN contacts. This: • Energises the GRA relay.
7.1 Standard schemes The schematic drawings for two standard synchronising schemes are shown in Figs 12.24 and 12.25. Figure 12.24 shows the manual synchronising scheme for an 11 kV switchgear distribution circuit. Figure 12.25 shows the manual and automatic synchronising scheme for a steam turbine-generator generator voltage circuit-breaker based on CEGB Standard 993610 [8] The equipment in the schematics is shown in the open, reset and de-energised condition, irrespective of whether the equipment in normal operation is closed or continuously energised. The equipment is connected to 63.5 V AC, 110 V AC, 110 V DC and 48 V DC and complies with the requirements of CEGB Specification US/12/50 [9] and CEGB Specification US/76/10 [101. Electronic equipment complies with CEGB Specification EES (1980) [11]. It should be noted that the schemes are designed to be readily extendible. Automatic synchronising relays and check synchronising relays are CEGB approved. To obtain type ap980
• Opens the GRA contact in the second OR coil circuit. (e) Initiate switch closing by rotating the discrepancy switch to the 'close' position. This energises the close interposing relay coil. It is worth noting that if the operator attempts to close the switch by operation of the discrepancy switch when the permitted synchronising conditions are absent, the following will result: • The second coil of OR will energise, causing OR relay to drop off. • OR contact in the close interposing relay coil circuit will open.
• The 'synchroniser locked-out' indicator is displayed. Lockout is now maintained until the energisation of the second OR coil via the SYN contact is interrupted, by selecting 'off' at the manual synchronising control selector switch.
Synchronising schemes
INCOMING {V T MANUAL SYNCHRONISING SELECTOR SWITCH 3 3 & 110/ LU
Q INSERT ACTUAL GRID VOLTAGE
- w
>
LL
Z
—
2
t
D
z
WLULL.
>_
BUSBAH ■ RuNNiNG) VOLTS
,r)
u 0 I I
I I I I
I I
IN OUT
CHECK SYNCHRONISING RELAY {SYN)
GI 7
° SLIP FEATURE SWITCH
—0 I
CB LLOC . O—
I
I
1
I
I
I I I I I'
I I I RU N N IN G VOLTS
F ON yi0
-a IYo lyo
••■
SYNC HROSCCPE
PP
oaf o 0 I I 0 1!
•
Q
6i0
INCOMING VOLTS
PHASE ANGLE VOLTMETER
48V
48v
SYNCHRONISER LOCKED OUT INDICATOR
GUARD RELAY (GA)
SYN ----O 0
°INSERT ACTUAL GRID VOLTAGE
LO
GUARD RELAY AUXILIARY {GRA)
DISCREPANCY SWITCH 00
w w uJ (fl Z Z UJ U.1 00 CL 0_ J 000 0 I IQ ! I I 1 ! I I I
0 01—
0 0
SYN 0 0
CLOSE z u9 z e cn` uj w INTERPOSING lciL, o RELAY c.t y
L _ POWER SUPPLY
FIG. 12.24 Manual synchronising of an 11 0/ distribution circuit 981
Synchronising
7.3 Steam turbine-generator — generator voltage circuit-breaker 7.3,1 Manual synchronising The procedure for manual synchronising is as follows (refer to Fie 2.25):
Chapter 12 • GR-2 opens. • GR-3 closes which, with SYN-2 already closed, completes the closing circuit except for the discrepancy switch.
(a) Connect the , ■ nchronisinv trolley to the generator synchroni.sing circuits by inserting the synchronising plug into the socket pro), ided at the Unit Desk.
(I) Initiate switch closing by rotating the discrepancy control switch I to the 'close' position. This completes the circuit which energises the close interposing relay coil IPC. Contact (PC-I initiates circuit-breaker closure.
(b) Select 'Generator/Transmission' (e.g., 23.5 kV/400 kV) voltage at the manual .synchronising control selector switch on the synchronising trolley.
(g) Key-operated control selector switch I is returned to the 'off' position which restores the circuitry to the initial condition,
(c) Select 'Manual Synch' at the key-operated control selector switch 1. Key-operated control selector switch 2 is already set at 'Check Operative'. This:
7.3.2 Automatic synchronising
(a) Select 'Auto Synch' at the key-operated control selector switch I, this:
• Energises the GSY relay, which closes GSY-1 and GSY-2 to connect running and incoming supplies to the synchroscope and voltmeters, and closes GSY-3 and GSY-4 contacts on either side of the close interposing relay coil.
• Energises the GSY relay, which closes GSY-1 and GSY-2 to connect running and incoming supplies to the automatic synchronising relay and closes GSY-3 and GSY-4 contacts on either side of the close interposing relay coil.
• Energises the OR relay, which closes OR-1 and OR-2 to connect running and incoming supplies to the check synchronising relay, closes OR-3 which energises HC relay and opens OR-4, removing SYN-2 contact by-pass.
• Energises C relay, which closes C-1.
• FIC relay is now energised, which opens HC-1 and HC-2, disconnecting the running and incoming supplies from the automatic synchronising relay unit, closes HC-3 and HC-5 in the 'manual synch' circuit on either side of the close interposing relay coil and opens HC-4 and HC-6 in the 'auto synch' circuit on either side of the close interposing relay coil. • Energises one coil of OR relay, which opens GR-1, disconnecting the 'check synch monitor' lamp, closes GR-2 (which energises GAR relay if the discrepancy control switch is prematurely operated) and opens GR-3 in the SYN-2 contact circuit. (d) The governor set point (incoming frequency) and generator transformer tap position (running voltage) are adjusted using the unit controls and the synchronising trolley instruments until satisfactory conditions are obtained. (e) The check synchronising relay confirms that conditions are satisfactory, by closing SYN contacts: • SYN-1 energises the second coil of GR relay, causing GR to drop off. • GR-I closes to illuminate the 'check synch monitor' lamp. 982
• Energises CA relay, which closes CA-1 (110 V AC supply to the automatic synchronising relay). • Energises NP relay, which closes NP-1 NP-2, NP-3 and NP-4. (b) Depress the 'auto synch start' button. This energises ST relay, which closes ST-I (start hold) and ST-2, ST-3 and ST-4 (speed and voltage control). (c) The automatic synchronising relay signals that conditions are satisfactory for synchronising. The duplicate 'auto synch' contacts close and energise the close interposing relay coil IPC. (d) Contact [PC-1 initiates circuit-breaker closure. (e) Key-operated control selector switch I is returned to the 'off' position, which restores the circuitry to the initial condition.
7.4 Site commissioning tests The following lists the test sequence for commissioning a synchronising scheme. It is for guidance only and is not intended to be a complete description of all the testing that may be necessary: (a) Wiring inspection and circuit/wiring diagram checks. (b) If applicable, confirm that the correct number and type of synchronising keys are available and that any excess keys are removed from site.
Synchronising schemes
CHECK SYNCHRONISING qELAY SYN 2
•
GENERATOR DESK STNCHRONiSING RELAY 035 MANLAL SYNCHRONISING RELAY
H
-C
/
OERiOE aELAY 11
Q7
I -
..i.
'2
ti
9
22
TONT' ROL SELECTOR SWITCH 2
CHECK SYNCH MONITOR
OR • • -•• ••]
SCAPU AUA LARY RELAY GAP 2
.
(
OR
OR 2
01
1 :
(c S
s GT '2—. 4
OR S SyN 2 0 01-0
•L'20 •
HC 3 3
CLOSE NTERPOSING RELAY 1PC 1 555 3 3SY 4 —0 3 •;
0
HC
0
C .
5 CONTROL SWITCH •
CONTROL SW!IC H • AUTO HC-4 NP-I SYNCH 2_0- r_3---.0 •DI1
•
AuTOMA TIC SYNCH START
ST
T
,
c, CONNECTING RELAY DC
= 7-
IT
CONTROL SELEGIC.R
CONTROL SELECTOR SWITCH •
CONNECTING RELAY AC
5WiTck
POTENTIAL SWITCHING RELAY
GENERATOR AUTOMATIC SYNCHRONISER ; PART)
L OC
T I
HF -
DEN SN ' ITCF4
l. _L 7 ' <" AUX SYNCHRONISING t uzzra h CONTACTS COMPLETE
LI
ST-3
,D,h,,—/DATA PPCCES5 ',3 1 72 I NPUT REL.A '
D
L.------ j syNc.,qc.NsiP.G comPLETE
ILOWER SPEED ST-4 0 0 TAP CHANGE { CONTROL
h
— —.:Al FI P•:
' RAISE SPEED
SPEEDER MOTOR CONTROL
--,
D
ST-2
0
,
E -S ' ' N C " C N ' S K : DS C u T
:••••
' RAISE VOLTS
SWITCHGEAR TI ME CONSTANT SETTING
ST-5 0
0E
,
DP1.2 , —.0 0—)
' LOWER VOLTS
MAIN GENERATOR TRANSMISSION SWITCH
OR-I
SYN -20
INTERPOSING VT5
01 -2
T
O ...E. S
,
D• .:LI-,-
Chapter 12
Synchronising (c) Synchronising trolley instrument checks: • That running and incoming volts are correctly displayed. • That with either voltage removed, the synchroscope pointer drops away to at least 45 ° and does not continue to rotate. • That 'fast' and 'slow' directions of synchroscope are correct. • That phase angle is correctly displayed. (d) Check synchronising relay checks: • That the DC power supply is applied correctly to the relay and that this supply is not used for any other purpose. • That the relay does not function with either AC supply absent. • Where applicable, set the relay to the required ti me setting. • Set undervoltage lockout and prove operation. • Prove correct phase angle operation. (e) Prove primary circuit phase rotation and phase relationship between voltage transformers. (f) Prove that the incoming and running volts are switched correctly to the synchronising equipment. By making the necessary temporary connections and using a common injection voltage at the main VT secondaries, prove that the incoming and running voltages at the synchronising equipment terminals, using an instrument of known accuracy, are 63.5 V + I 070. If necessary adjust the interposing transformer tap setting. Following live synchronisation checks with the switch closed, the voltages at the equipment terminals should be rechecked with the primary voltage at nominal value. (h) Perform a number of live manual synchronising tests with 'check operative' selected. (i) Automatic synchronising relay (if applicable): • Check that the auxiliary power supply is not used for any other purpose. • Select the required synchronising method. • Voltage and speed' matching tests. Two variable frequency and voltage sources are used to simulate the incoming and running supplies. In a series of tests, the voltage and freduency are altered in accordance with raise/lower signals. The voltage differences at which signals cease/commence and the slip frequency at which the 'switch close' signals commence/cease are recorded. 984
• Phase angle error test. The test arrangement is as above, except that the dosing of each 'switch close' signal output contact is recorded in such a way that angular error can be determined. • Prove lockout facilities.
• Check the range of speed governor pulse/pause length. • Check the switch closing signal pulse length. • Check the VA loading on incoming, running and auxiliary supply. • Check remote indications. • Check that the connections and switching from the automatic synchronising relay to voltage and frequency controls are correct. • Adjust switch closing time, maximum slip frequency, voltage error, low voltage lockout and speed governor pulse/pause widths to the required settings. Note:
If the governor rate is not known, this can be determined by measuring the voltage beat waveform between the incoming and running voltages using a UV recorder. Starting at about 47 Hz, a continuous 'raise' signal is applied to the speed governor (the running frequency is assumed to be constant) which produces a trace as shown in Fig 12.26. The governor rate can be calculated from: a g = 2(ti
t2)/ti t2(ti
t2) Hz/s
(j) Prior to live synchronising tests, 'dead bar' (i.e., with the switch electrically isolated) synchronising tests may be carried out. A UV recorder is used to monitor the beat waveform, switch close initiation signal and a signal from the switch which indicates when the primary contacts have closed. The unit is run-up and the automatic synchronising relay allowed to perform the synchronising operations. From the recording, the accuracy of closing the switch can be determined as shown in Fig 12.27. If the switch closing time t3 is more than the setting increment from the selected switch closing time, then the setting should be changed accordingly and the test repeated. (k) Finally live synchronising tests are carried out, recording all necessary parameters including the beat waveform and the switch initiation signal. A number of synchronising operations are performed. These tests are carried out with the generator transformer tap at the lowest and highest position with the incoming frequency at 47 and 51 Hz,
•
• Synchronising schemes
ft
1
2 NOT TO SCALE
FIG. 12.26 Determination of governor rate
followed by a test with the incoming and running voltage and frequency set equal. From the recordings obtained, the phase error can be checked
SWITCH INITIATION
SWITCH CLOSED
SWITCH CLOSED
SWITCH INITIATION
rult--31wr
BEAT WAVEFORM
by projecting the waveform to the position where phase coincidence would otherwise have occurred, as shown in Fig 12.28.
BEAT WAVEFORM
1 I
\ \
I N
I/ /1 ./ ••••`
.) PHASE ERROR
PHASE ERROR
6
" -4-1 2
•
1
1
—11■ -4— 1,
74180' CUT OF PHASE I.
= 180
PHASE COINCIDENCE
= 180' x
t i = 180= i= 180' x1 2 t
NOT TO SCALE
1
PROJECTED PHASE COINCIDENCE NOT TO SCALE
FIG. 12.27 Dead bar synchronising
FIG. 12.28 Live synchronising
985
Chapter 12
Synchronising
8 References CEGB Design :Memorandum 066/1: Application and control of emergency gas turbine generating plant on new power stations
[6] ESI Standard 35-5: Generator voltage transformers for 500/ 660 MW turbine-generators I 7 1 ESI Standard 35-6: Generator voltage transformers for gas turbines [8]
CEGB Standard 993610: Standardisation of synchronising equipment
CEGB Standard 99384: Standard circuit ratings, current trans former and ,.oltaae transformer requirements for main plant
[9]
CEGB Specification US/ 12/50: General technical requirements for ancillary electrical equipment
14] Engineering recommendativn 515 Part 3: Basic diagrams for voltage and current transformer secondary circuits
[10]
CEGB Specification US/ 7 6/10: Instrument and control equipment, general technical requirements
t-5 1 CEGB Standard 994274: Standard circuit diagrams of generator single-phase VT circuits
[IL] CEGB Specification EES {1980): General •;pecification for electronic equipment
121
BS3941: Specification for voltage transformers: 1975
[3]
986
SUBJECT INDEX AC commotator motors. 626 AC cons crier drives 7 ri ble pecd. 626-62 ' Access covers portable earth isolated phase busbars, 310 Access lighting, 599 cranes, 817 Access platforms enclosures isolated phase busbars, 313 Access ways lighting, 593 Accommodation batteries, 757-760 telecommunications rooms. 652 Active failure rate power systems reliabriity evaluation, 92 Actuator drives low voltage switchgear capability, 391 Advance angle synchronising definition, 950 Advanced gas-cooled reactors auxiliaries systems, 16 cables segregation, 436 cabling, 430
electric motors, 641-642 loss of grid supplies, 34 Olympus gas turbines, 36 oxygen, 821 station electrical systems analysis diagram, 152 computer reliability analysis, 166 Air circuit-breaker switching Dinorsvig, 345 Air admission valves pumped-storage plant protection, 914 Air compressors automatic operation fire fighting, 863 diesel generators, 784 electric motors, 858 electrical services, 858-861 fire fighting, 863 Air conditioning electrical services, 862 enclosures isolated phase busbars, 309 Air heaters electrical services, 862 Air pipework diesel generators, 784 Air receivers diesel generators, 784 testing, 795 Aircraft obstruction lighting, 598 Alarm bells power feeds cabling, 491 Alarm signals siren systems. 722 Alarms (see also Audible alarms; Emergency alarm signals; Nuclear alarms) battery chargers, 769,772 control boards, 772
conservators low oil level, 904
DC systems. 766 diesel generators, 792 testing, 796 fire fighting, 863 lists, 820 remote uninterruptable power supply systems, 62 thermostats gas production plant, 824 Alum dosing pumps water treatment plant power distribution. 840 Aluminium cables, 435 conductors generator connections, 288 power cable fittings, 533 electric motors, 629 generator main connections, 304 power cable fittings bolting, 535 preparation termination connections, 535 Aluminium hydroxide additive ethyl vinyl acetate, cables, fire performance, 526 Ambient temperature cables maximum operating temperature, 450 Ambulance services communication links, 650 Ammeters switchgear, 373 low voltage, 405 Amplitude modulation telecommunications, 680 Analogue signals control and instrumentation cables, 476 Analysis reliability power systems, control, 96 Analysis parameters power systems computer reliability analysis, 161 Antennas. 684 coaxial cables characteristic impedance, 686 coupling equipment, 702 input impedances, 687 leaky feeders, 691 lightning protection, 705 mounting arrangements. 687 power handling capability, 687 radiating cables, 691 radio frequency received power, 684 radio paging systems, 667 radio systems pumped-storage power stations, 736 telecommunications, 684-696 typical arrangements, 689 vehicle, 714 Anti-collision systems cranes, 679, 816 Antimony trioxide additive polyvinyl chloride, cables, fire performance, 526 Arcing DC switchgear, 413
987
Subject Index
Arcing rate electrostatic precipitators, 854 Arcing time Fuses definition, 412 Area grids control centres communication links. 650 Amiour loss ratios cables, 451 Armour wire cross-sectional area, 616 Asbestos fire barriers, 548 Ash handling plant electrical services, 842-851 Ash hoppers mobile electrical control, 848 Aspiration diesel generators, 788 Asynchronous generator synchronising, 952 Asynchronous system synchronising, 952 Audible alarms cabling, 491 Audible calling units. 721 Audible warning systems, 652 auxiliary telecommunications room, 653 Auto loading diesel generators performance tests, 797 Auto starting diesel generators Performance tests. 797 Automatic controls air compressors, 859
Automatic synchronising, 955,957 burdens, 978 steam turbine-generators generator voltage circuit-breakers, 982 Automatic synchronising relays, 956,957,969 Automatic voltage control electrostatic precipitators, 854 Automatic voltage regulators data load flow analysis, power systems, computer reliability analysis, 145 stability analysis. 183 diesel generators, 791 performance tests, 797 testing, 796 generator transformers protection, 904 loss of grid supplies, 33 models stability analysis, 181 power systems performance analysis, 179 stability analysis power systems, 180 system stability analysis, 184 Auxiliary electrical systems computer reliability analysis, 136 Auxiliary pOwer systems fault levels, 326 voltages, 326 Auxiliary switches, 369 Auxiliary systems protection, 920-943 Auxiliary Telecommunications Room, 652.653 Auxiliary transformers air-cooled, 264 cast-resin insulation, 265 cooling, 263 design, 263 insulation, 263 magnetising inrush currents, 269
988
synthetic liquid filled, 267 Average outage duration GRASP 1 presentation of results, Ill power systems reliability, quantitative evaluation, 90 Average repair time power systems reliability evaluation, 92 Avon gas-turbine generating set electrical auxiliaries systems. 35 Back to back starting pumped-storage plant protection, 911 Ball bearings electric motors, 636 Barring gear diesel generators, 782 protection, 793 Battery chargers —see Chargers Batteries (see also Lead acid cells; Plante batteries; Recombination cell batteries), 749-763 accommodation, 757-760 ambient temperatures, 757 boost charging, 761 control, 772 capacity, 750 cell life, 761 charging, 750,760-763 circuit monitoring, 769 connectors corrosion, 762 containers, 750 failure, 762 corrosion acid/air interface, 761 current feedback control boards, 771 direct wire telephone systems, 722 discharge, 750 discharge rate, 750 electrical systems, 69-70 electrolytes contamination, 762 emergency supply equipment, 749 fire fighting, 867 fully charged, 750 initial charge, 767 inspection, 762 life. 763 li mited voltage recharging, 761 maintaining charge, 767 maintenance, 760-763 maintenance-free, 749 negative plates, 750 nickel-cadmium cells, 752 on-site testing, 760-763 pasted flat plate lead-acid cells, 751 plate groups, 750 plates, 750 positive plates, 750 rating, 750 recombination cells, 752 replacement, 763 sealed lead-acid, 752 separators, 750 temperature, 750 terminals corrosion, 762 tests, 760-763 tubular plate lead-acid cells, 750 types, 750-753 uncharacteristic behaviour of odd cells, 763 uninterruptable power supply systems, 60 voltage, 749 • Battery rooms, 757
Subject Index
access. 760 lighting, 597 main connections, 757 ventilation, 757 Battery systems, 763-766 DC systems tests, 763 duplication, 766 float charging, 760 Beam clamps cable support systems, 498 Bearings (see also Ball bearings; Frictionless bearings; Plain bearings; Rolling element bearings; Split-type roller bearings; Tilting-pad bearings) electric motors, 635-637 pumped-storage plant protection, 9 11,914 Bellows insulation isolated phase busbars, 305 Bidirectional branches power systems computer reliability analysis, definition. 95 Black start electrical systems, 29 gas-turbine generators, 35 B lowdown air admission valves pumped-storage plant protection, 914 Body proximity loss radiating cable, 693 Boiler feed pumps electric switchgear, 38 electric motors, 640 electrical systems, 39 Boiler feedwater chemical-dosing plant electrical services, 836 Boiler houses cables, 506 Boiler make-up feedwater treatment, 836 electrical services, 835 Boilers circulating pumps protection, 878 protection, 871-879 Bolting terminations power cable fittings, 535 Boost charging batteries, 761,762,767 control, 772 Booster pumps water treatment plant power distribution, 839 Brackets cable support systems, 496 Brakes lifts, 819 Braking resistors loss of grid supplies, 33 Braking systems cranes, 811 Branches definition power systems, computer reliability analysis, 95 power systems computer reliability analysis, numbering, 94 Brass preparation termination connections. 536 British Telecommunications plc cables, 659 on-site duct routes, 659 on-site requirements, 659 segregation, 659
circuits electrical isolation, 660 communication links. 650 construction sites, 741 national cable network access, 658-660 telephone services, 660-662 Bromotnfluoromethane fire fighting, 862 Building factor transformers cores, 200 Buildings lightning protection, 582 special considerations, 583 metal decking lightning protection, 582 Busbar indices evaluation techniques power systems, computer reliability analysis, 105 GRASP 1 presentation of results, 111,112 power systems computer reliability analysis, 113-115 Busbars (see also Isolated phase busbars) data load flow analysis, power systems, computer reliability analysis, 144 DC switchgear short-circuit withstand strength, 414 earthirig switchgear, 368 low voltage switchgear short-circuit withstand strength, 391 materials generator main connections, testing, 315 phase angles system stability analysis, 184 PQ
load flow analysis, 123 protection. 930 PV load flow analysis, 123 slack load flow analysis, 124 power systems, computer reliability analysis, 147 switchgear low voltage, 402 rated short-time current, 380 types load flow analysis, 123 voltages system stability, 183 system stability analysis, 184 Bushings connections transformers, 228 generator main connections testing, 314 Cl channels surface mounting cable support systems, 497 Cab control cranes, 811 Cable boxes connections transformers, 231 Cable flats lighting, 593 Cable glands, 531-533 bonding earthing systems. 550 construction, 531 design, 531 earth bonding, 568 earthing bond connections
989
Subject Index
sizes, 567 installation, 533 sizing, 532 Cable interface loss radiating cable, 694 Cable nem ork systems applications. 486 design. 486 jumpenng, 482 494 Cable palling hand, 520 installation, 519 Jamming. 520 motorised rollers, 521 running bond techniques. 521 winch, 520 Cable support systems application, 501 bridge and tower assemblies, 505 design, 501 ladder racks, 517 Cable supports seismically qualified, 509 Cable systems, 429-435 control and instrumentation design, 480-482
design, 601. 603 design and management techniques, 601-606 heat-detecting, 865 layout, 429-435, 603 planning, 601 Cables (see also Coaxial cables: Control cables; Earth bond cables; Earth cables; Linear heat detecting cables; Radiating cables: Short-time fireproof cables; Triaxial cables) 415 V, 441 3.3 kV, 439-441 11 kV, 437-439 accessories, 531-540 auxiliary systems protection, 930 British Telecommunications plc, 659 bunched fire performance, 523 buried direct in the ground installation, 457, 517 thermal parameters, rating factors, 614 thermal resistance, 452 cable support systems, 494-512 design, 494 design and management, 603 carriers, 499 cleating design. 513 concrete troughs installation, 517 continuous operation current rating, 448 contract management information, 604 control and instrumentation. 476-494 corrosive gases fire performance, 529 current ratings permissible, 453 DC power circuits, 441 design, 442-443 design clearance, 604 ducts installation, 457, 517 thermal parameters, rating factors, 615 thermal resistance, 453 elastomeric-insulated current ratings, 610 electric motors starting, 463 starting current, 463 starting times, 464 electrical tests, 447
990
fire barriers, 540-550
fires, 545 installation, 435, 512-522, 604 reduced fire propagation, 523 insulation cables, 443 interference
control and instrumentation. 476 layout, 435 linear heat detecting, 442 maximum route lengths, 618 maximum temperature ambient temperature, 450 mechanical performance, 444-447 multicore interference, 480 interference, control and instrumentation, 480 shaped solid aluminium conductors, 535 multicore PVC-insulated reactance, 609 resistance, 609 multipair earthing networks, 566 interference, comml and instrumentation. 477 paper insulation, 437 performance fire conditions, 522-531 PVC-insulated current ratings, 611 rating factors, 454 reactance, 608 reactor safety trip systems, 434 restraint, 512 routing, 604 safety nuclear power stations, 431 scheduling, 604 segregation, 429 separation, 429 short-time fireproof, 442, 522 single fire tests. 523 single-core, 438 fire performance, 524 in parallel, installation, 457 single-core elastomeric-insulated resistance. 608 sizes, 466 steelwork cleating. 513 telephones ducts, construction sites, 741 thermal resistance, 451 in free air, 452 toxic gas emissions fire performance, 530 tunnels. 502 lighting, 593 types, 435-447 control and instrumentation, 476 voltage regulation, 464 Cabling, 427-622 control and instrumentation earthing, 569 gland bonding, 569 electrolytic cells hydrogen production, 825 emergency alarm signals, 724 fire fighting, 866 heating and ventilation. 862 lighting, 600 low smoke systems, 663 e onon-site future trends, 745 private automatic exchanges, 661 siren systems nuclear power stations, 732
Subject Index
switchgear, 369 Low voltage, 402 system design, 11 telecommunications on-site. 661-663 telephones user distribution frames, 663 total project information, 605 Cage induction motors, 62-1 -625. S02. boiler feed pumps, 640 double-cage rotor. 625 starting current. 624 stator windings, 624 tris lot rotor, 625 Cantilever arms cable support systems, 502.516 Capacitors failure rates, 945 generator main connections testing, 315 Capacity batteries, 749 Capstan effect transformers performance, 216 Carbon dioxide storage plant electrical services, 830 uses, 821 Cartridge fuselink definition. 410 CEGB corporate telephone network, 650 Cell life batteries, 761 Central control equipment radio paging systems, 667 Central control rooms control panel power supplies, 724 controllers emergency alarm signals, 723 lighting, 598 supervisor's desk speech communication, 726 Central Electricity Generating Board— see CEGB Certification switchgear, 334-340 Charger output voltage uninterruptable power supply systems, 62 Chargers, 766-775 batteries, 69-70 alarms, 769 current feedback, control boards, 771 display, 772 electronic circuit boards, testing, 774 fire fighting, 867 low voltage detection, 769 On-site tests. 774 output voltage, testing, 773 performance tests, 773 power supplies. 768 power supply, control boards, 772 protection, 769 routine tests, 774 soak tests, 774 supply voltage transients, 768 temperature rise tests, 773 testing, 773 type testing, 773 visual checks. 773 equipment, 769 ratings, 767 Charging (see also Boost charging; Float charging) batteries, 750,760-763 Charging systems duplication, 766 Check inoperative
synchronising, 957 Check synchronising relays, 956,966 Chiller units electrical services. 862 Chimneys aircraft obstruction lighting, 598 lightning protection, 578 Chlorination plant electrical systems maintenance interlocking. 82 lighting. 597 Chlorosulphonated polyethylene rubber cables fires, 523 Chokes battery chargers, 768 gas production plant, 822 Circuit-breakers air break feeder circuits, 467 motor circuits, 468 closed/open state indication, 373 control, 331 DC. 414 definition, 334 design, 352-380 electrical interlocks, 361 fault levels station electrical systems, computer reliability analysis. 168,169 faults generators, protection, 905 first-pole-to-clear factor, 356 generator voltage. 895 protection, 905 steam turbine-generators, synchronising, 982 steam-turbine-generators, synchronising supplies, 979 synchronising, 961 generator voltage/HV protection, 905 low voltage, 405 low voltage switchgear capability. 391 maintenance, 379 moulded case future trends, 422 operating mechanisms, 379 phase-segregated generators metalclad, 423 rated short-circuit breaking current, 356 rated short-circuit making current, 357 reclosing power systems, computer reliability analysis. 100 stuck probability reliability evaluation. 93 transmission voltage synchronising, 962 type tests, 336 Circuits data load flow analysis, power systems, computer reliability analysis, 144 stability analysis, power systems, 180 Circulating pumps boilers protection, 878 Circulating water pumps nuclear reactors electric motors, 645 Circulator main drive motors nuclear reactors, 642 Cleating cables. 513 Coal delivery, 842 handling plant electrical services, 842-851
991
Subject Index
Coal plant control rooms electrical control, 844 Coal-fired boiler units electric motors, 640-641 Coal-fired power stations reference design electrical systems, system indices, 115 Coaxial cables control and instrumen ation, 476 Coded-key devices swiichgear, 361 low voltage, 404 Coding electrical systems quality assurance, 45 Conine Consultatif International de Radio sequential single frequency code signalling, 683 trunked radio systems, 675 Comite Consuliatif International de Telegraphique et Telephonique, 675 dual tone multi-frequency signalling, 683 Commissioning cable systems, 601 earthing systems, 573 network cable systems, 490 Common mode failure diesel generators, 778 evaluation power systems, reliability evaluation, 92 rate power systems, reliability evaluation, 93 Communication systems commissioning, 651 maintenance, 651 Component active failure power systems reliability evaluation, 92 Component passive failure power systems reliability evaluation, 92 Components power systems computer reliability analysis, numbering, 94 Composite error current transformers, 285 Compressed air starting system diesel generators, protection, 793 Compressed air systems generator main connections testing, 315 Compression fittings power cables copper conductors, 534 Compressor rooms lighting, 592 Compressors (see also Air compressors) diesel generators testing, 795 generator main connections testing, 315 hydrogen production control, 827 Computer programs interactive power systems, reliability evaluation, 93 power systems branch numbering, 93 component numbering, 93 reliability evaluation power systems, 91-92 Computers draughting, 159 electrical systems, 74-75 Concrete troughs cables installation, 517 Condensates
992
conductivity high. protection, 882 polishing plant electrical services, 836 treatment electrical services, 835 Condensers vacuum low protection, 881 Conductors aluminium generator main connections, 304 power cable fittings, 533 cables electrical resistance, 451 maximum temperature. 449 temperature rise, 450 connection to plant isolated phase busbars, 310 continuously-transposed transformer windings, construction, 208 copper power cable fittings. 534 crimped terminations control cables, 537 expansion joints isolated phase busbars, 306 isolated phase busbars, 304 joints isolated phase busbars, 311-312 painting isolated phase busbars, 309 power cables terminations, 533-537 switchgear rated short-time current, 380 terminations control cables, 537-539 thermal parameters rating factors, 612,613 transformer windings continuously-transposed strips, construction, 208 windings transformers, construction, 206 Connections HV/LV protection, 905 Connectors batteries corrosion, 762 Conservation oil transformers, 227 Conservators low oil level alarms, 904 Construction sites electrical supplies equipment, 414-421 telecommunications, 741-744 telephone cable ducts, 741 Contactor gear mechanical plant. 805 Contactors controlgar gas production plant, 822 low voltage, 406 DC, 414 electrically-held definition, 334 low voltage switchgear capability, 391 Continuous tone calling signalling systems radio communications, 673 Control boards battery chargers, 770 Control cables conductors
Subject Index
terminations, 537-539 multicore, 441,476 fire performance, 524 multipair. 441,476 nuclear power stations safety, 431 separation. 430 Control cabling post-tnp cooling systems, 433 reactor safety trip systems, 433 Control circuit trans formers switchgear low voltage, 408 Control equipment cubicles cranes. 813 Control and instrumentation air compressors hydrogen production, 827 cable systems design, 480-482 cables, 476-494 installation, 514 multipair, fire performance, 524 earth networks, 562 electrochlorination plant electrical services, 832-834 gas production plant, 822 gland bonding cabling, 569 marshalling boxes earthing networks, 566 Control rooms noise mechanical plant, electrical services, 805 Control station systems cranes, 811-813 Control switches circuit-breakers low voltage, 405 Location, 373 Control systems nuclear power stations cabling, 430 Controlgear, 325-426 construction. 342-352 contactors low voltage, 406 definition. 326 design, 342-352 low voltage. 391-409 design, 393 temperature rise tests, 339 Controllers public address systems nuclear power stations, 728 radio systems personal, pumped-storage power stations, 738 siren systems nuclear power stations, 730 Converter/inverter motors fault current power systems, computer reliability analysis. 151 Converters modelling power systems, performance analysis, 189 Conveyors coal electrical services, 844 fire fighting, 863 electrical services, 850 Coolant pumps PWR reactors electric motors, 642 Cooler banks transformers, 234 Coolers control transformers, 237
tank-mounted transformers, 233 Cooling auxiliary transformers, 263 electric motors, 631-634 forced isolated phase busbar, 297-299 forced air isolated phase busbar. 298 generator main connections future trends, 323 liquid isolated phase busbar, 298 nuclear power stations computer reliability analysis. 140 post-trip Magnox nuclear power stations, 13 switchgear, 353 Cooling fans diesel generators, 786 radiators diesel generators, protection. 793 Cooling systems diesel generators, 785 Cooling towers aircraft obstruction lighting, 598 Cooling water auxiliary generators temperature high, protection, 923 electrochlorination plant electrical services, 830-834 Low flow auxiliary generators, protection. 923 pumped-storage plant protection. 914 pumps cabling, 430 treatment electrical services, 835,837 Cooling water pumps auxiliary diesel generators, protection, 793 Cooling-oil transformer windings heat production, 213 Copper cables, 435 conductors crimped terminations, 537 generator connections, 288 power cable fittings, 534 preparation termination connections, 536 transformers, 196 windings manufacture checks. 244 Core insulation screen II kV terminations, 539 Core-loss measurement transformers, manufacture checks. 244 transformers, 198 Core-plates transformers manufacture checks, 244 Cores transformers construction, 201-205 Corrosion batteries acid/air interface, 761 connectors. 762 terminals, 762 Corrosive gases emission • tables, fire performance, 529 Cranes access lighting, 817
993
Subject Index
anti-collision systems, 679, 816 ash-grabbing electrical control, 848 cab control, 811 control station systems, 811-813 control systems combined LF and VHF/UHF, 679 low frequency radio systems, 677 HF. 678 VHF, 678 controls, 813-816 cross-traverse electric services, 817 earthing, 817 electrical services, 806-818 floodlights, 817 grabbing coal unloading, electrical services, 843 long travel alternative supplies, 817 electric services, 816 maintenance socket outlets, 817 motion control direction, 807 speed, 807 motor drives, 807 nuclear power stations DC motors, 807 electrical services, 817 pendant control, 812 power distribution, 807 power supply, 807 radio control, 811 radio systems, 677 travel motion supply systems, 816 travelling coal unloading, electrical services, 843 Creepage switchgear low voltage, 402 Crimped terminations conductors control cables, 537 Critical current tests switches, 338 Cross-linked polyethylene cables, 437 Cross- linked polythene insulation cables, 443 Cross-linking insulation cables, 437 Crossbar systems telephone exchanges, 664 CURB03, 457 Current limiting reactors design, 276-278 Current making/breaking capability DC switching devices, 414 Current ratings cables permissible, 453 continuous operation cables, 448 Current ratio errors current transformers, 284 Current sharing cables single-core, in parallel, 457 Current source converters, 627 Current transformers auxiliaries protection, 921 battery chargers, 770 construction, 286 design, 281 isolated phase busbars, 309-310
994
performance curves, 935 protection, 890, 892 switchgear, 372 low voltage, 405 Current-limiting fuselink definition, 411 Cut set power systems computer reliability analysis, 96 Cat -off characteristics fuses definition, 41 1 Cut-off current fuses definition, 411 Cut-through tests cables, 446 Cycloconverters, 627 Damper windings turbine-generators stability analysis, power systems, 180 Data British Telecommunications plc, 661 telecommunications construction sites, 744 Data handling systems electrical systems quality assurance, 45 DC circuits earthing, 67 DC filters battery chargers, 770 DC motors, 628-629 DC power circuits cables, 441 DC systems 48 V, 67 110 V, 65 220V, 65 250V, 65 alarms, 766 analysis. 67-69 battery-backed, 763 system tests, 763 design, 65 duties, 64 electrical systems, 64-70 emergency drives. 766 emergency lighting, 766 plant control, 766 switchgear closing, 763 telecommunications, 766 voltage limits, 766 DC transformers banery chargers, 772 DC tripping systems, 914-920 DC voltage transformers battery chargers, 770 Decommissioning electrical systems economics, 37 Definite time relays characteristics. 932 Delta connections isolated phase busbar, 301 Desulphufisation flue gases retrofitting, 9 Detectors fires, 865 Dielectrics transformers, 196 Diesel generators, 775-798 3.3 kV synchronising, 963 synchronising supplies, 980
Subject Index
AGR nuclear power stations a uxiliaries systems. 18 air pipework, 788 auxiliaries. 778 onstruct ion, 790 c control, 79 design. 779.790 earthing networks. 565 elecirical deign. 790 einergem suppl:, fault analysis station electrical systems. computer reliability analysis, 170 Fire protection, 778 harmonic suppressors earthing networks, 565 in-service operational testing. 797 installation, 775 loading, 775 Location, 778 lubrication, 780 mechanical design, 790 neutral earthing resistors. 565 numbers, 775 operational system tests, 797 protection, 791,792 high winds, 777 purposes, 775 rating, 775 seismic protection, 778 starling, 775,783 station electrical systems voltage profile, 155 synchronising, 959,974 testing, 794-798 types, 778 water jacket heaters protection, 794 Digital signals control and instrumentation cables, 476 Dinorwig circuit-breaker switching air storage capacity, 345 electrical auxiliaries systems, 22 generator transformers water cooling, 235 phase-reversal disconnectors, 349 protection, 906 switchgear, 341 Direct wire telephone systems, 653,717-722 common equipment location. 722 Direction of radiation antennas. 685 Disc bushings isolated phase busbars, 305 Discharge rate batteries, 749 Disconnectors definition, 334 Distributed fixed station systems radio systems, 673 Distribution networks power system instability, 176 Div6bution pillars portable substations, 417 District survey laboratories nuclear power stations, 733 Disturbances power systems computer reliability analysis, 176 short-circuit power systems, computer reliability analysis, 176 Documentation electrical systems quality assurance, 46 Dosing pumps electrochlorination
electrical services, 834 Draft tube valves pumped-storage plant protection, 913 Drain earth switchgear, 328 Draught plant electric motors, 640 Drawings electrical systems quality assurance, 46 Drax Completion cabling, 428 Drax power station electrical auxiliaries system, 10 guaranteed instrument supplies system station, 55 Drax power stations guaranteed instrument supplies system unit. 54 Dual tone multi-frequency signalling. 683 Ducts cable pulling, 520 cables installation, 457,517 thermal resistance, 453 telephone cables construction sites, 741 Duplexers coupling equipment antennas, 702 Dust handling plant electrical services, 842-851 Dust hoppers mobile electrical control. 848 Dust pumps controls,. 851 Dynamic braking overcurrent pumped-storage plant protection. 906 Dynamic output voltage effects unintemmtable power supply systems. 63 Earth bars generator connections, 302 Earth bond cables sizes, 563 Earth cables circular solid aluminium conductors, 535 installation. 562 Earth electrodes buried horizontal strips. 556 resistance measurement, 572 sizing, 552.556-562 Earth fault currents earthing systems cables, 554 Earth faults auxiliary generators protection, 923 auxiliary transformers protection, 921 cables, 461 generator stators. 886-891 generator transformer connections protection. 905 generator transformers protection, 903 standby unit transformers, protection, 903 Earth networks construction, 562-567 control and instrumentation, 562 plant bonding, 562-567
995
Subject Index
Earth potential earthing systems cables, 550 Earth resisuvity measurement, 567-572 Earth rods earth electrodes, 561 earth electrodes, 556 Earth strips earth electrodes, 561 Earth systems impedance. 572 Earthing battery chargers. 769 control and instrumentation cabling, 569 cranes, 817 DC circuits, 67 diesel generators testing, 795 electrostatic precipitators, 855 gas production plant, 824 generator main connections, 320-321 high resistance generator stators, 887-891 lifts, 820 low impedance generator stators, 886-887 maintenance generator main connections, 321-323 power cabling, 570 switchboards low voltage, 403 switchgear, 367 duty, 390 Earthing switches, 368 design, 351 generator main connections testing, 315 type testing, 339 Earthing systems acceptance criteria cables, 551 cables, 550-574 design, 552-556 commissioning, 573 remote neutrals cables, 552 resistance, 554 routine tests, 573 Earthquakes (see also Safe-shutdown earthquakes) cable support systems, 569 cranes nuclear power stations, 817 diesel generators protection, 778 Eddy current loss transformers, 199 Effective radiated power antennas, 685 Effluent pumps water treatment plant power distribution. 840 Elbow terminations electric stress II kV terminations, 540 Electric motors (see also AC commutator motors: Cage induction motors; Circulator main drive motors; Converter/inverter motors; DC motors; Induction motors; Linear motors; Slipring induction motors; Squirrel-cage induction motors; Synchronous motors), 623-648 415 V parameters, fuse sizes, 617 protection, 940 3.3 kV earthing networks, 565
996
II
kV
p lant bonding. 565
AC electrical services, 802 auxiliary protection, 925 auxiliary drives, 640-645 circuits cables, 468 construction. 629-637 cranes, 807 DC, 803 cranes, nuclear power stations, 807 design, 629-637 design standards, 801 electrical auxiliaries systems, 7 electrical services, 801-806 fault currents power systems, computer reliability analysis, 166 future trends. 645 gas production plant, 821 heating and ventilation. 861 large electrical systems, 39 low voltage switchgear capability, 391 performance, 623-629 protection cranes, 807 ratings, 801 run - up load flow results, 191 speed control, 39 start-up load flow results, 191 starting cables, 463 station electrical systems, load flow analysis. 138 starting current cables, 463 starting times cables, 464 supply voltages, 801 technical requirements, 637-640 testing, 645 types. 623-629 water treatment plant, 840 Electric stress 11 kV terminations core insulation screen, 539 Electrical auxiliaries systems, 6-9 li mitations, 38 transformers, 7-8 Electrical circuits design, 603 Electrical clearances switchgear low voltage, 402 Electrical interlocks circuit-breakers closure, 361 Electrical services mechanical plant, 799-867 Electrical supplies construction site equipment, 414-421 Electrical systems analysis, 84 - 192 principles, 84 -89 quality assurance, 89 techniques, 85 capital costs, 36 choice, 35-46 consequential costs, 37 descriptions, 4-29 design, 1-83 economics, 36 main generators, 4-5
Subject Index
monitoring, 70-83 needs, 2-4 operational requirements, 35 performance, 29-35 calculations, 39 performance analysis future developments, 189-191 reliability, 36 evaluation. 87 reliability analyas control, 96 failure, criteria. 96 security, 2 standby plant reliability, 36 station load flow analysis, computer reliability analysis, 138 Electrochlorination plant cooling water electrical services, 830-834 power distribution, 834,839 production control panel, 833 Electrodes — see Earth electrodes Electrolytic cells hydrogen production, 824-827 Electromagnetic interference relays, 945 Electronic equipment battery chargers, 768 mechanical plant. 805 Electronic governors diesel generators. 789 Electrostatic precipitators, 851-855 electrical supplies, 853 high voltage chamber enclosures, 855 high voltage control cubicles, 854 Emergency alarm signals siren systems, 722 Emergency control centre nuclear power stations, 732 Emergency drives DC systems, 766 Emergency generation, 9 Emergency lighting DC systems, 766 Emergency operational lighting, 596 Emergency pushbuttons generators protection, 902 Emergency stop diesel generators, 792 Emergency stop pushbuttons pumped-storage plant, 911 Emergency supply equipment, 748-798 Emergency telephone systems construction sites, 742 Emergency trip control mechanical plant electrical services. 804 Enclosures electric motors, 630-631 expansion joints isolated phase busbars, 306 insulation generator main connections, 304 isolated phase busbars, 304 access platforms, 313 equipment, 304 structural steelwork, 314 mechanical plant electrical services, safety, 803 painting isolated phase busbars, 309 switchgear, 358 low voltage, 401 wall seals isolated phase busbars, 305 Encounter rate
power systems reliability, quantitative evaluation. 90 Environment mechanical plant electrical services, 804 switchgear. 332 uninterruptable power supply systems, 60 Essential operational lighting, 596 Essential systems electrical auxiliaries systems, 9 Ethyl vinyl acetate cables fire perforrnance. 526 Ethylene propylene rubber cables, 437 fires, 523 insulation cables, 443 Ethylene vinyl acetate copolymer insulation cables, 443 Evaluation techniques power systems computer reliability analysis, 105,109 Excitation failure generators, 902 generator-motors incorrect, protection, 912 generators loss, protection, 898 Excitation busbars generator connections, 302 Excitation control diesel generators, 791 Excitation equipment diesel generators. 791 pumped-storage plant protection, 911 Excitation transformers pumped-storage plant protection, 912 Exciters diesel generators, 791 testing, 794 Exhaust manifolds diesel generators, 789 Exhaust pipework diesel generators, 789 Exhaust pressure high turbines protection, 881 Exhaust steam temperatures high protection, 886 Exhauster fans AC commutator motors, 626 Explosiongs terminal boxes 3,3kV motors. 390 Facsimile services construction sites, 744 Failure criteria power systems, reliability analysis, 96 Failure events GRASP presentation of results, 112 power systems computer reliability analysis, 108 definition, 96 second order power systems, computer reliability analysis. 105, 107 third order power systems, computer reliability analysis, 107, LOS Failure rate
997
Subject Index
GRASP 1 presentation of results. Ill power systems reliability. quantitative evaluation, 90 Failures types power systems, computer reliability analysis. 98 Fans isee (Aso Cooling fans, Exhaust fans} coaling trans furnie rs, 237 diesel generators testing, 795 electrical services. 862 iransfonners cooling, 239 Fast &coupled method network equation solution reliability analysis, 128 Fast frequency shift keying signalling systems, 682 Fault analysis station electrical systems computer reliability analysis. 167,170 Fault currents cables. 459 evaluation power systems, computer reliability analysis, 164 network branches power systems, computer reliability analysis. 165 three-phase power systems, computer reliability analysis, 150 Fault level analysis data power systems, stability analysis, 180 power systems computer reliability analysis, 148-173 Fault levels auxiliaries power systems. 326 break calculations, station electrical systems, computer reliability analysis. 169 Fault voltages evaluation power systems, computer reliability analysis, 164 Faults (see also Earth faults; Phase to phase faults; Short-circuit faults; Turn to tum faults) clearances slow, system stability analysts, 188 duration power systems, system stability, 183 location power systems, system stability, 183 power systems system stability. 183 station plant electrical auxiliaries systems. 34 three-phase-to-earth power systems. system stability, 183 Feed pumps sea water electrical services. 834 voltage profile, 156.157.158 Feeder circuits main protection, 620 Feedwater (see alSo Boiler feedwater; Boiler make-up feedwater) treatment electrical services, 836 Film records generator main connections testing, 319 Filtered water pumps water treatment plant power distribution. 839 Fire barriers cables, 540-550 integrity, 547 performance. 542-546 stability. 546
998
fire tests performance criteria, 548 insulation cables, 547 penetrations seals, cables, 548 pre-fabricated cables, 542 proximity to fires cables, 545 Fire dampers, 866 Fire detectors power feeds cables, 494 Fire doors cables, 548 Fire fighting equipment electrical services, 862-867 power feeds, cables, 494 Fire protection diesel generators. 778 waterspray oil-filled transformers, 240 Fire pumps automatic operation, 863 diesel-driven, 863 electrical services, 863 Fire services communication links, 650 Fire tests cables. 523 Ore barriers cables, 546 performance criteria. 548 wires, 523 Fireman's control systems lifts, 820 Fires cables gormance. 522-531 cablpienrf nuclear power stations, 430 magnitude cables. 545 oil cooling isolated phase busbar, 298 proximity to barriers cables. 545 transformers, 196 transformers compound layout, 239 types cables. 545 Firing pulse amplifiers battery chargers control boards, 771 First-pole-to-clear factor circuit-breakers, 356 switchgear, 380 Fixed station cubicles lightning protection, 706 Fixed station transmitters, 698 Flammable gases production plant lightning protection, 583 storage plant lightning protection, 583 flexible connectors braided isolated phase busbars, 307 isolated phase busbars. 306-309 laminae isolated phase busbars. 307 Float charge batteries rating, interconnected station system. 767 rating, interconnected unit system, 767 Float charging
Subject Index
batteries, 760 Flood control system lifts, 820 Flooding cabling nuclear power stations, 430 Floodlights cranes. 817 FIOON
battery rooms. 757 Flue gases desulphunsanon retrofitting, 9 switchgear. 38 Fluorescent tubes lighting, 600 Flux fractions lighting, 590 Flywheels diesel generators, 782 Foams pipework fire fighting, 862 Foil windings transformers, 270 Foot insulators isolated phase busbars. 305 Forced outages power systems computer reliability analysis, 103 types power systems, 98 Formel NF auxiliary transformers insulation, 267 Forward power relays turbines protection, 883 Fossil-fired power stations auxiliaries systems, 10 cabling segregation, 429 Foundations diesel generators, 783 Freezer air driers alarm generator transformers, 904 Frequency generator main connections. 304 maintenance, 948 Frequency errors synchronising, 954 Frequency modulation telecommunications, 680 Frictionless bearings electric motors, 635 Frost gas production plant protection, 822 water treatment plant electrical services, 842 Fuel injection diesel generators, 782 Fuel oil heating, 857 pipework diesel generators, 788 storage tanks heating, electrical, 857 lightning protection, 583 Fuel oil plant electrical services, 855-858 Fuel oil pumps diesel generators protection, 793 electrical services, 857 Fuel oil systems diesel generators, 787
Fumes cables fires, 523 Fuse elements definition, 411 Fuse switches definition. 334 Fuseboards lighting heating, 599 Fusegear low voltage, 391-409 design, 393 Fuselink contacts definition, 411 Fuselinks main circuit switchgear, 390 required performances, 412 switchgear low voltage, 408 Fuses, 409-413 415 V characteristics, 931 choice, 938 co-ordination with switchgear, 389 definition, 410 high breaking capacity, 930 switchgear low voltage. 405 Gas circulators nuclear reactors electric motors, 641,643,644 voltage profile, 156, l57 Gas detection hydrogen production plant, 826 Gas discharge lamps lighting, 592 Gas production plant electrical services, 820-830 Gas storage plant electrical services, 820-830 Gas turbines chimneys lightning, protection systems, 581 mechanical trips, 925 . on-site generation, 9 protection, 924 synchronising facilities, 958 unit transformers II kV, earth terminals, 565 Gas-turbine generating set Avon electrical auxiliaries systems, 35 Olympus electrical auxiliaries systems, 35 Gas-turbine generators 11 kV synchronising, 962 synchronising supplies, 979 electrical auxiliaries systems. 35 stators plant bonding, 565 synchronising, 973 Gas-turbine inverters uninterruptable power supply systems, 55 Gases — see Carbon dioxide: Flammable gases; Methane; Nitrogen; Noxious gases; Oxygen: Propane; Toxic gases Gatehouse controllers emergency alarm signals, 724 Gauss-Seidel method network equation solution reliability analysis, 126 Generator busbar system earthing transformers, 272
999
Sublect Index
Generator earthing transformers, 271 Generator motors incorrect excitation levels protection, 912 stationary field windings heating, protection, 912 Generator neutral earthing transformers design, 271 Generator transformers, 5-6, 219. 200 availability. 253 compound layouts, 240 connections, 310 currents, 253 design, 253-260 economics of operation, 259 heights, 254 high set instantaneous overcurrents protection, 903 HV bushings protection, 905 HV inverse time overcurrents protection, 903 i mpedance, 253 impulse strengths, 253 internal faults protection, 904 neutral earthing, 565 noise, 253 overload capabilities, 253 performance, 255 protection, 902-905 pumped-storage plant protection, 906 reliability, 253,255 single-phase, 254 interchangeable, 254 tap-changers, 253,254 protection, 892 transport, 251,253 voltages, 253 Generator voltage transformers design, 279 Generators (see also Main generators; Synchronous generators) asynchronous running protection, 898 auxiliary electrical protection, 923 protection, 922-925 capacitance, 304 data load flow analysis, power systems, computer reliability analysis. 145 stability analysis, power systems, 180 disconnecting switchgear, 340 earth bond networks, 565 earthing, 320 excitation loss, protection, 898 excitation busbars, 302 fault contributions main connections, 304 fault currents power systems, computer reliability analysis, 166 line ends, 300 main connections, 39,287-324 capacitance, 304 evolution, 288 future trends, 323 operating temperature, future trends, 323 motoring protection, 902 neutral ends, 300 off-load voltage profile, 156 output main connections, 304 power system instability, 176
1 000
protection, 886-902 representation fault currents, computer reliability analysis, (62 rotor angles power systems. performance analysis, 178 runaway pumped-storage plant, protection. 911 single fed system stability analysis, 184 stator windings toss of water flow, protection, 901 stators negative phase sequence, 898 neutral earthing, 320 synchronising, 949,952 sub-synchronously. 953 switch disconnectors, 341 tee-off connections transformers, 300 voltage circuit-breakers, synchronising, 961 switchgear, 340-352 voltage circuit-breakers, 895 protection, 905 voltage profile, 157 voltage switchgear, 319-320 earthing, 302 windings, 299 G1DEAN, 67 Gland bonding control and instrumentation cabling, 569 power cabling, 570 Gland plates cabling switchgear, 402 Glare direct lighting, 591 disability lighting, 591 discomfort lighting, 591 indirect lighting, 591 lighting. 590 Governors (see also Electronic governors; Mechanical governors) composite steam/hydro models, stability analysis, 182 stability analysis, power systems, 180 data load flow analysis, power systems, computer reliability analysis, 145 stability analysis, 183 diesel generators, 789 performance tests, 797 testing, 796 electric loss, protection, 886 frequency stabilisation, 948 power systems performance analysis, 179 pumped-storage plant protection, 913 rate synchronising, definition, 952 set point definition, 951 speed droop definition, 951 stability analysis power systems, 180 system stability analysis, 184 GRASP 1 power systems computer reliability analysis, presentation of results, Ill reliability evaluation, 91 GRASP 2
Subject Index
power systems reliability evaluation, 91 Greases electric motors bearings, 636 Grid netitsorks fault contribution generator main connections. 304 Grid Sy Stems operation criteria, 3 power station interface computer reliability analysis. 147 voltages electrical systems. economics, 37 Grit pumps controls. 851 Guaranteed instrument supplies systems, 48,54 Guard relays synchronising, 957,966 Guide vanes pumped-storage plant protection, 913 Halon 1301 Ore fighting, 862 Harmonic analysis power systems performance analysis, 189 Harmonic distortion transformers, 269 Harmonic suppressors auxiliary transformers, 275 Harmonies electric motors fault currents, power systems, computer reliability analysis, 151 Hartlepool switchgear, 341 air, 345 Hazard warning lights, 598 Headgates pumped-storage plant protection, 914 Heat exchangers forced air cooling isolated phase busbar, 298 maintenance transformers, 237 Heaters see also Air heaters compressors, 859 Heating cables, 588-601 control gear, 861 electrical services, 861-862 supplementary cables, 598-599 Heysham 1 switchgear, 341 air, 345 Heysham 2 cabling, 428 design electrical auxiliaries systems, 16 power system, 432 switchgear, 341 uninterruptable power supply systems, 55 High set instantaneous overcumnts generator transformers protection, 903 unit transformers protection, 903 Humidifiers electrical services, 862 Hydrastep system water level protection. 874 Hydraulic control fluids
contamination overspeed trip. protection. 883 turbines protection, 880 Hydro power stations cabling segregation. 429 electrical auxiliaries systems, 22 Hydrochloric acid polyvinyl chloride burning. 523 Hydrogen battery rooms, 757 compressors control. 827 high temperature protection, 901-902 production electrolytic cell process, 824-827 methanol chemical reaction, 827-829 uses, 821 water cooling flow stator, 902 Hydrogen bromide cables fire performance, 530 Hydrogen chloride cables fire performance, 530 polyvinyl chloride cables, fires, 545 Hydrogen plant electrical services, 805 lighting, 597 Hysteresis loss transformers silicon content, 198 Illumination (see also Lighting) levels, 593 I mpedance earth electrodes measurement, 572 generator transformers, 253 unit transformers. 262 variation transformers, 219 Impulse strength generator transformers, 253 Impulse testing transformer windings, 212 I mpulse tests transformers. 249 Indicating instruments switchgear, 373 Induction motors current decays power systems, computer reliability analysis, 150 data load flow analysis, power systems, computer reliability analysis, 145 stability analysis, 183 power systems computer reliability analysis, 160 pulse-width-modulated converters. 628 representation power systems, computer reliability analysis, 164 run-up load flow results, 190 power systems, stability analysis. 189 slip system stability analysis, 185 speed system stability, 183 start-up load flow results, 190 system stability analysis, 184
1001
Subject Index
variable-speed slipring boiler feed pumps, 640 Inductors fault levels poy.er svstems, computer reliability analysis. 151 uninterruptable poser supply systems, 62 Infra-red cameras temperature measurement 3 isolated phase hushars Inspection li ghting, 599 Installation cable systems, 601 cables, 453.512-522 contract management information. 604 troughs. 517 power cables single-core, 455 site generator main connections, 314 transformers, 251-253 Instrument transformers design, 278-286 Insulation ageing oxygen, 227 transformers, testing. 250 auxiliary transformers, 263 cables, 437 II kV, 438 cast-resin auxiliary transformers, 265 dryness transformers. monitoring, 245 electric motors life, 802 thermal overload relays, protection, 928 windings, 634-635 windings, type tests, 634 tire barriers cables. 547 generator voltage transformers, 280 graded transformer windings, construction, 210 paper cables, 437 shrinkage transformers, 218 switchgear, 354 3.3kV, 180 low voltage. 402 transformer windings construction, 210 transformers, 196.198 manufacture checks, 244 power frequency overvoltage tests, 247 Insulators electrostatic precipitators high voltage, 855 generator main connections testing. 314 isolated phase busbars, 304-306 Enterconnecuons electrical aux,iliaries systems. 8 Interconnectors fault levels station electrical systems, computer reliability analysis, 1 67, 168 transformers, 72 Interference electrostatic precipitators. 855 half IF, 717 multicore cables control and instrumentation, 480 multipair cables control and instrumentation, 477 radio systems. 715-717 Interference theory
1002
cables control and instrumentation, 476 Interlock types definition, 72 Interlocking, 70-83 electrical systems maintenance, 75 generator main connections maintenance, 323 mechanical plant electrical services, 804 operational electrical systems. 71 Interlocking equipment cable network systems, 485 Interlocking schemes application electrical systems. 72 general. 72 Interlocks (see also Electrical interlocks; Maintenance interlocking; Mechanical interlocks; Travel interlocks) cranes, 813-816 diesel generators, 792 electrical mechanical plant. electrical services, 804 mechanical mechanical plant, electrical services, 804 sequence operational electrical systems, 74 switchgear DC systems, 765 turbines protection, 883 Intermodulation products radio systems, 715 Inverse time overcurrent generator transformers protection, 903 unit transformers protection, 903 Inverse time relays characteristics, 931 current grading, 935 time grading, 935,936 transient overreach, 936 Inverter output voltage tolerance uninterruptable power supply systems, 62 Ion-exchange resins water treatment electrical services, 836 Ionisation chamber detectors fires, 865 Iron transformers, 196 Isolated phase busbars, 287 air-insulated delta connections, 301 cooling forced, 297-299 design, 294-297 electrically-continuous short-circuit, 289 forced air cooling. 298 forces, 289-294 liquid cooling, 298 oil cooling transfmer cooling, 298 operation, 289-294 system description, 299-303 voltage rise fault conditions. 294 water cooling, 298 Isolation lighting, 599 power systems computer reliability analysis, 100 Isolators coupling equipment
Subject Index
antennas. 702 definition, 334 Isotropic radiator radio signals propagation, 683 I-brackets cable support systems, 504 Jamming cable pulling, 520 Joints
conductors isolated phase busbars, 311-312 earth bars earthing. switchgear, 367 expansion conductors, isolated phase busbars, 306 enclosures, isolated phase busbars, 306 resistance temperature measurement, isolated phase busbars, 313 lumpering cable network systems. 482-494 Key exchange boxes electrical systems maintenance interlocking, 81 Knee point EMF current transformers, 285 Labelling switchboard circuits, 373 Ladder racks cable support systems, 499,501,503,517 cleating, 513 Lead acid cells see also Batteries gas recombination power supplies, telecommunications, 657 Lead resistance synchronising, 978 Leakage reactance generator transformers, 253 transformers, 197 Lifts audible alarms, 820 brakes, 819 car control facilities, 819 car emergency hatches. 820 car lighting, 819 cars, 819 drive systems electrical, 818 hydraulic, control systems, 819 earthing, 820 electrical services, 819-820 fireman's control systems, 820 landing equipment, 819 maintenance facilities, 819 motor rooms equipment, 818 motors
protection, 819 power distribution, 818 power supply, 818 requirements. 818 shafts flooding, 820 lighting, 820 types, 818 Light obscuration smoke tests cables, fire performance, 527 Lighting (see also Access lighting; Aircraft obstruction lighting; Emergency lighting; Emergency operational lighting; Essential operational lighting; Floodlights; Illumination; Luminaires) appraisal, 595 battery rooms, 757 cables, 588-601
design, 588-596 economics, 591 emergency, 596-597 general, 589 lamps, 621 lift cars, 819 lift shafts. 820 local, 589 localised, 589 objectives, 588 special areas, 597-598
Lightning fuel oil storage protection, 858 gas production plant protection, 821 i mpulse voltage testing generator main connections. 314 magnitudes. 575 protection, 556.574-587 antennas, 705 cables, 550 fuel oil storage tanks, 583 protection earth electrodes resistance, 587 protection systems design, 581 inspection, 587 records, 587 sideflashing, 584 testing, 587 return stroke, 575 risks, 575 transformer windings testing, 212 transformers i mpulse tests, 249 Lights paging systems, 666 Limit switches cranes, 813-816 Limited energy sources power systems reliability evaluation, 92 ti me limit power systems, reliability evaluation, 93 Limited fire hazards cables, 523 Limited voltage recharging batteries, 761 Line currents generator connections, 304 Line data entry computer reliability analysis power systems, 160 Linear differential equations solution, 135 Linear heat detecting cables, 442 Linear motors future trends, 646 Littlebrook D cabling, 428 electrical auxiliaries system, 10 guaranteed instrument supplies system station, 53 unit, 48 Load disconnection automatic power systems, performance analysis, 179 Load flow analysis complex variables, 124 data requirements power systems, computer reliability analysis, 144 power systems, 117-148 computer reliability analysis, 174,175 . program construction, 120 station electrical systems computer reliability analysis, 138
1003
Subject r nd ex
Load flow calculations power systems computer reliability analysis, 174, 175 Load flows convergence accuracy power systems, computer reliability analysis, 1 47 data power systems, stability analysis, 180 number of iterations in solution algorithm power systems. computer reliability analysis. 147 power network, 120 Load losses transformers, 200 Loading resistors generator main connections testing, 315 generator neural earthing transformers, 272 Locking circuit-breakers, 373 electrostatic precipitators, 855 Loss of boiler water protection, 871 Loss of electric load protection, 873 Loss of feedwater protection, 876 Loss of feedwater flow protection, 871 Loss of generation power systems reliability, quantitative evaluation, 90 Loss of grid supplies electrical systems, 33 load flow analysis computer reliability analysis, 140 Loss of lubricating oil pressure turbines protection, 880 Loss of pumping power pumped-storage plant protection, 911 Loss of revenue power systems reliability, quantitative evaluation, 90 Loss of steam demand protection, 879 Loudspeakers nuclear power stations, 729 Low drum levels boilers protection, 871 protection, 873 Lubricating oil low pressure auxiliary generators. protection, 923 priming diesel generators, 782 priming system diesel generators, 792 temperature low auxiliary generators, protection, 923 turbines cabling. 430 water jacket heaters diesel generators, 794 Lubricating oil systems DC motors, 628 Lubrication diesel generators, 780 Lugs soldered power cable conductors, terminations, 533 Luminaires classification, 590 lighting, 621 types, 589 utilisation factors, 591 Luminous area
1004
lighting, 590 M87 control system operational description, 706 Machine controllers stability analysis power systems. 180 Magnetising inrush current auxiliary transformers, 269 Magnox nuclear power stations electrical auxiliaries system, 12 Main connections busbar system functions, 287 Main distribution frame private automatic exchanges, 662 Main earth networks construction, 562 Main generators electrical systems, 4-5 Main inlet valves pumped-storage plant protection, 914 Main steam valve spindles overspeed trip protection, 883 Main telecommunications moms, 652 equipment, 653 power supplies, 653 Main transformers battery chargers, 770 Main water treatment plant electrical services, 836 Maintenance electrical systems, 44-45 operational, 44 generator main connections
earthing, 321-323 interlocking electrical systems. 75 lighting, 599 rate power systems, reliability evaluation, 93 safety electrical systems, 44 ti me power systems, reliability evaluation, 93 uninterruptable power supply systems, 62 Maintenance and commissioning telephone jack systems, 653, 722 pumped-storage power stations, 741 Maintenance interlocking electrostatic precipitators, 855 Maintenance socket outlets cranes, 817 Maintenance transition rate power systems computer reliability analysis, 103 Manual synchronising, 955,956 burdens, 978 steam turbine-generators generator voltage circuit-breakers, 982 Manual trip levers turbines protection, 882 Markov state-space models power systems computer reliability analysis, 101 Matching transformers protection, 890 Matrix tripping systems, 915 Mean time between failures power systems reliability, quantitative evaluation. 90 Mean time to repair power systems . reliability, quantitative evaluation, 90 Mechanical governors
Subject Index
diesel generators, 789 m e chanicai interlocks switchgear low voltage. 404 Mechanical plant electrical services, 799-867 control circuits, 803 trip circuits, 803 Mechanical trips auxiliary generators, 923 Melamine insulation transformers, 270 Mercury Communications Ltd telecommunications future trends, 744 Meta!clad switchgear movable earth, 328 work using, 329 Metallic screens cables, 451 Meter rooms lighting, 592 Methane production plant electrical services, 829-830 uses, 821 Methane, bromotrifluorofire fighting, 862 Methanol hydrogen production, 827-829 Method of symmetrical components power systems computer reliability analysis, 162 Microwave links telecommunications future trends, 744 fvfidel 7131 auxiliary transformers insulation, 267 Milling plant electric motors, 640 Mineral oil transformers, 196 Minimal cut set power systems computer reliability analysis, 96 Minimal cuts GRASP 1 presentation of results, 111 Minimal paths GRASP 1 presentation of results, 111 power systems computer reliability analysis, 96 computer reliability analysis, deduction, 96 Minimum cut sets power systems computer reliability analysis, deduction, 96 Moisture transformers insulation ageing, 227 Monitoring battery chargers, 769 electrical systems, 71 Monitoring systems nuclear power stations cabling, 430 Motor circuits 415 V, 474 protection, 927 3.3 kV, 474 protection, 927 II kV, 473 protection, 927 main protection, 620 Motor-generator set schemes, 46 Motoring generators, 952
protection, 902 Motorised rollers cable pulling. 521 Motorola-Stomo CAF2200 system operational description, 708 National cable networks British Telecommunications plc telecommunication circuits. 658 National grid systems communication links, 650 Negative phase sequence generators protection, 898 Network branches power systems fault currents, computer reliability analysis, 165 Network cable systems commissioning. 490 plant-mounted devices, 490 testing. 490 Network connections fault conditions power systems. computer reliability analysis, 163 Network diagrams data entry power systems, computer reliability analysis, 141 drawing power systems, computer reliability analysis. 141 Network equations solution reliability analysis, 126
Neutral earthing transfouners. 271-276 Neutral eanhing equipment isolated phase busbars, 314 Neutral earthing resistors. 555 3.3kV cables, 439 11 kV cables, 438 Newton-Raph son method network equation solution reliability analysis. 127 Nitrogen storage plant electrical services, 830 uses, 821 Nodal analysis load flow power network, 121 Nodal failure events GRASP 1 presentation of results, I ll Noise
enclosures isolated phase busbars. 305 generator transformers, 253 local-to-plant mechanical plant, electrical services, 805 mechanical plant electrical services, 805 suppression radiotelephones, 714 Non-linear differential equations stability analysis power systems, 179 Noxious gases cables fires, 442 Nuclear alarrns power feeds cables, 494 Nuclear emergencies radio services. 734 Nuclear incidents emergency telecommunications, 732 Nuclear plant electrical systems
1005
Subject Index
operational requirements, 35 loss of grid supplies. 34 Nuclear power stations battery chargers safety, 769 cabling segregation. -130 cranes DC motors, 807 electrical services. 817 electrical auxiliaries systems. 7 electOcai systems. 4 desien, busbar indices, 113 emergency lighting, 596 essential systems, 9 fire barriers cables, 542 lighting, 588 loss of grid supplies, 33 mechanical plant electrical services, 805 on-site generation, 9 standby earth faults protection. 903 telecommunication requirements, 652 telecommunications, 726-734 tripping schemes, 915 Nuclear reactors AGR electric motors, 641-642 emergency supply equipment, 749 PWR electric motors, 642-645 Number systems power systems computer reliability analysis, 94 Numbering electrical systems quality assurance, 45 Numerical indices power systems reliability, quantitative evaluation, 90 Oil coolers diesel generators, 780 Oil flow washers transformer windings, 215 Oil-fired boiler units electric motors, 640-641 Oil-fired power stations electrical systems maximum load, voltage profile, 154 minimum load, voltage profile, 154 station electrical systems analysis diagram, 152 Oils (see also Fuel oil; Lubricating oil; Mineral oil) circulation transformer windings, heat production, 215 preservation transformers, 227 transformer cooling isolated phase busbar, 298 transformers dryness, 227 Olympus gas-turbine generating set AGRs• 36 Avon, 35 On-line computing interactive electrical systems, analysis. 86 Operating air plant switchgear, 353 Operating frequency antennas, 685 Operating time fuses definition, 412
1006
Operational telephone systems. 651 Operations support centres nuclear power stations, 734 Optical smoke detectors. 865 Orifice plates water cooling transformers, 235 Outage time annual GRASP 1, presentation of results. Ill power systems reliability, quantitative evaluation. 90 Outages forced station plant, electrical auxiliaries systems, 34 planned station plant, electrical auxiliaries systems, 34 station plan( electrical auxiliaries systems, 34 Output frequency uninterruptable power supply systems, 63 Output voltage adjustment uninterruptable power supply systems, 62 Output voltage waveform distortion uninterruptable power supply systems. 64 Over frequency protection pumped-storage plant. 910 Overfluxing generator transformers protection, 904 Overload capability generator transformers. 253 unintemmtable power supply systems, 64 Overload currents cables, 462 Override synchronising, 952 Oversheaths cables mechanical performance. 445 Overspeed auxiliary generators protection, 923 pumped-storage plant protection, 910, 913 Overspeed trips diesel generators, 789 turbines protection, 883 Overvoltage protection battery chargers. 769 Overvoitages generators protection. 888 pumped-storage plant protection, 911 Oxygen insulation ageing transformers, 227 Oxygen index tests fire performance cables, 526 PABX — see Private automatic branch exchanges Paging systems, 666-668 inductive loops, 666 lights, 666 sounders, 666 uses, 668 Painting conductors isolated phase busbars, 309 enclosures isolated phase busbars, 309 Paints flame retardant
Subject Index
cables, 523 temperature •:ensttive isolated pilaw busbars, 313 Paper insulation cables, 437 transformer windings, heat production, 214 transformers. drying out, 24.4 Passo,e Catlurc rate
poser systems reliability evaluation, 92 Paths power systems computer reliability analysis, 96 PAX — see Private automatic exchanges Pay telephones construction sites, 743 Peak lopping gas-turbine generators, 35 Pendant control cranes. 812 Penetration seals fire barriers cables, 549 flexible fire barriers, cables, 549 pre-formed fire barriers, cables, 549 rigid fire barriers, cables, 549 Performance analysis power systems. 117-191 Periodic output voltage modulation uninterruptable power supply systems, 64 Personnel safety, 3-4 Phase angle errors current transformers, 284 voltage transformers, 278 Phase measurement synchronising, 967 Phase relationships transformers, 194 Phase segregation generator connections, 288 Phase to phase faults auxiliary transformers protection, 921 generator stators, 891-897 generator transformer connections protection, 905 generator transformers protection, 903 Phase-reversal disconnectors pumped-storage schemes, 349 Phasor diagrams current transformers, 281 Phasor groups transformers, 194 Pipes fuel oil storage heating, electrical. 858 Pipework (see also Air pipework; Exhaust pipework) , air diesel generators, 788 compressed air systems generator main connections, testing, 315 diesel generators testing, 795 fuel oil diesel generators, 788 Plain bearings electric motors, 635,636 Plant bonding earth networks, 562-567 Plant control DC systems, 766 Plant-mounted devices
network cable systems, 490 Plante batteries (see also Batteries). 749 auxiliary telecommunications rooms. 656 battery stands. 756 cell lids, 755 chemistry, 756 charging, 756 discharge. 756 electrolytes, 755 group bars. 753 heavy duty lead-acid chemistry, 753 description. 753 positive plate, 750 intercell connectors, 755 main telecommunications rooms, 653 negative plates, 753 plastic containers, 755 plate interconnections, 753 polarity identification, 755 positive plates, 753 power supplies telecommunications, 657 separators, 753 terminal pillar seals, 755 terminal pillars, 755 testing, 762 vent plugs, 755 Plastics cables, 437 Polarity antennas, 685 Pole slipping generators protection, 900-901 Police communication links, 650 Poly ether ether ketone insulation cables, 443 Polychlorobiphenyls auxiliary transformers insulation, fire resistance, 263 Polyethylene cables, 437 Polyphenol oxide insulation cables, 443 Polyvinyl chloride additives cables, fire performance. 526 burning critical mass, 523 cables, 435, 437 fire performance, oxygen index tests, 526 fires. 523 fires, noxious gases, 442 hydrogen chloride cables, fires, 545 Porcelain post insulators isolated phase busbars, 304 Portable distribution units 110V, 417 415/240 V. 417 Portable drain earths generator main connections maintenance, 321 Portable earthing access covers isolated phase busbars, 310 Post insulators isolated phase busbars, 304 Post-trip cooling nuclear power stations cabling, 430 Post-trip cooling systems control cabling, 433
1007
Subject Index
Post trips station electrical systems load flow analysis. 138 Power cable systems design, 447-476 Power cables conductors terminations, 533-537 rnuIticore earthing networks, 566 fire performance. 524 installation. 514 installation, ladder racks, 513 vertical runs, installation, 516 nuclear power stations safety, 431 ratings earthing systems, 550 single-core installation, 455 Power cabling earthing, 570 gland bonding, 570 Power distribution AC, 600 DC, 600 Power distribution system li ghting heating, 599 Power factor generator main connections, 304 Power flows large systems performance analysis, 179 Power frequency overvoltage tests transformers, 247 Power handling capability antennas, 687 Power network load flow, 120 Power semiconductors unintermptable power supply systems. 62 Power stations grid system interface computer reliability analysis, 147 operating criteria, 2-3 types, 9 Power supplies telecommunications, 652 Power systems analysis program developments, 85 cables, 588-601 instability minimising, 176 minor cables, 598-599 performance, 85 analysis, 88 performance analysis, 117-191 reliability quantitative evaluation, 90-91 reliability evaluation, 89-117 Power transmission power system instability, 176 Power trips electrical systems, 32 Pre-arcing time fuses definition, 412 Precipitator control houses, 854 Precipitator surge-hoppers trace heating, 849 Pressboard insulation transformers, 244 Pressure reducing valves water cooling
1008
transformers, 235 Pressure relief devices generator transformers protection, 904 Pressure switches network cable systems, 490 Pressurised water reactors electric motors, 642-645 loss of grid supplies, 34 nuclear power stations auxiliaries systems, 19 Primary earths generator main connections maintenance, 321 switchgear, 328 Private automatic branch exchanges, 665-666 accommodation. 656 construction sites, 742 future trends, 747 pumped-storage power stations, 735 telephones, 650 Private automatic exchanges, 663-665 cabling, 661 future trends, 747 pumped-storage power stations, 736 telephones, 650 Private circuit networks British Telecommunications plc, 661 Private mobile radio equipment, 669 radio frequency bands, 670 Product quality electrical systems, 46 Propane storage cylinders lightning protection, 584 Prospective breaking currents fuses definition, 411 Prospective current of a circuit definition, 411 Protection, 868-947 auxiliaries systems, 920-943 battery chargers, 769 co-ordination, 931-943 generator main connections maintenance. 323 maintenance electrical systems, 44 overall logic. 870-871 switchgear DC systems, 765 Protection equipment reliability, 943-947 Protection relays digital type electrical motors, 929 monitoring, 945 electromechanical, 945 electronic, 945 microprocessors, 946 solid state reliability, 945 type testing, 945 Protective panels cranes, 813 Protective systems components switchgear, low voltage, 404 design, 870 Public address systems auxiliary telecommunications room, 653 nuclear power stations, 727, 731 Public switched telephone networks, 658 British Telecommunications plc, 660 communication links, 650 Pulse-width-modulated converters. 628
Pump-turbines protection, 913
Subject Index
Pumped storage schemes phase-reversal disconnectors, 349 Pumped-storage plant Protection, 906-914 Pumped-storage power stations telecommunication requtrements, 652 telecommunications, 734-741 Rumps see also Alum dosing pumps; Boiler feed pumps; Booster pumps: Circulating water pumps; Coolant pumps; Cooling water pumps; Dosing pumps: Dust pumps: Effluent pumps. Feed pumps: Filtered water pumps: Fire pumps; Fuel oil pumps: Grit pumps; Raw water pumps; Recovered water pumps; Sump pumps: Water circulation pumps: Water pumps) cooling water cabling, 430 diesel generators testing, 795 Quality assurance electrical systems, 45 generator main connections, 314 power systems computer reliability analysis, 112-113 transformers, 243 Quartzoid bulbs fire detection, 865 Radar anticollision systems cranes, 679 Radiating cables antennas, 691 Radiators cooling fans diesel generators, protection, 793 corrosion transformers, 234 diesel generators, 786 transformers, 233 Radio interference mechanical plant, electrical services. 805 station UHF power feeds, cabling, 494 station VHF power feeds, cabling. 494 Radio channels allocation, 670 pumped-storage power stations, 738 Radio control cranes, 811 Radio frequencies fixed stations, 696-704 Radio frequency bands private mobile radio equipment, 670 Radio frequency modulation systems, 680 Radio paging systems, 667 central control equipment, 667 communication links, 651 construction sites, 743 direct speech, 668 manual controllers, 667 non-speech component parts, 667 pumped-storage power stations, 736 Radio services nuclear emergencies, 734 Radio signals propagation, 683 Radio systems, 668-717 communication links, 651 construction sites, 744 cranes, 677 future trends, 745 interference, 715-717 personal
pumped-storage power stations, 736 remote control lightning protection, 706 trunked, 670,674 future trends, 745 Radiotelephones future trends, 746 handportable construction sites, 744 pumped-storage power stations, 738 transceivers handportable, 711-713 vehicle-mounted, 713-714 Radiotelephony systems, 669-677 Rated accuracy limit primary current current transformers, 285 Rated breaking capacity fuses definition, 411 Rated breaking currents switchgear, 380 Rated duration of short-circuit switchgear, 357,389 Rated normal currents switchgear, 355,380 Rated operating sequence switchgear, 357,389 Rated peak withstand currents switchgear earthing circuits, 355 Rated short-circuit breaking currents circuit-breakers, 356 Rated short-circuit making currents circuit-breakers, 357 switchgear, 384 Rated short-time currents switchgear, 380 Rated short-time withstand currents switchgear earthing circuits, 354 Rated voltage factors voltage transformers, 279 Rated voltages switchgear, 352 Rating factors cables, 454 Ratio errors voltage transformers, 278 Raw water pumps water treatment plant power distribution, 839 Rayleigh distribution loss radiating cable, 694 Reactance cables single-core elastomeric-insulated, 608 multicore PVC-insulated cables, 609 Reactive power li mitation on synchronous plant representation, power systems, computer reliability analysis, 135 Reactor safety trip systems cables, 434 cabling, 431 control cabling, 433 Reactors off-load voltage profile, 155 start sequence load flow analysis, 140 tripping cabling, 430 Receivers fixed station, 700 Reclaimers coal electrical services, 847 Recombination cell batteries
1009
Subject Index
advantages, 658 disadvantages. 658 maintenance, 752 power supplies telecommunications, 657 Recovered water pumps water treatment plant power distribution, 840 Rectifier transformers desien, 269 Rectifiers (see also Thyristor recta tiers) battery chargers. 768 electrochlorination. 834 electrostatic precipitators. 855 gas production plant. 822 hydrogen production control, 827 Reference transformers bartery chargers, 770, 772 Regeneration ion-exchange resins water treatment, electrical services, 836 RELAPSE power systems reliability evaluation, 91 Relative humidity isolated phase busbars, 310 switchgear, 332 Relay rooms lighting, 592 Relay systems operational interlocking schemes electrical systems, 71 Relays (see also Definite time relays; Forward power relays; Guard relays; Inverse time relays; Protection relays: Thermal overload relays: Thermal relays) diagnostic features, 947 digital type, 947 electromagnetic interference, 945 electronic analogue, 947 switchgear, 373 unreliability, 943
Reliabihty electrical systems, 36 evaluation. 87 generator transformers, 253 monitoring uninterruptable power supply systems, 62 power systems evaluation, 89-117 evaluation assessments, scope, 90 quantitative evaluation, 90-91 protection equipment, 943-947 uninterruptable power supply systems, 60 Reliability evaluation analysis electrical systems, 85 Remote control cables nuclear power stations, safety, 431 switches emergency supply equipment, 749 Remote control systems lightning protection, 706 Repair rate power systems computer reliability analysis, 103 Repairs power systems computer reliability analysis, 100 uninterruptable power supply systems, 62 Replacements power systems computer reliability analysis, 100 Resistance
cables single-core elastomenc-insulated, 608 earth electrodes measurement, 572
1010
multicore PVC-insulated cables, 609 Resistame of free space radio signals propagation, 683 Resistance thermometers network cable systems, 490 Resistive loss transformers, 200 Resistors failure rates, 945 Restoration types power systems, 98 Risk analysis lightning protection, 578 Rolling element bearings electric motors, 635 Rolling sphere method lightning zone of protection, 578 Rotor angles generators power systems, performance analysis, 178 synchronous generators system stability, 183 RTEmp auxiliary transformers insulation, 267 Rubbers cables, 437 Running bond techniques cable pulling, 521 Safe shutdown earthquakes cabling nuclear power stations, 430 Safety advanced gas-cooled reactors cabling, 431 cranes nuclear power stations, 817 electric motors PVVR reactors. 642 electrical systems, 44-45 gas production plant electrical services, 821 interlocking electrical systems, 45 lifts, 820 Magnox nuclear power stations, 12 maintenance electrical systems, 44 mechanical plant electrical services, 803 nuclear electrical systems, 45 nuclear power stations battery chargers. 769 personnel, 3-4 remote control cables nuclear power stations, 431 Safety control air compressors, 859 Safety Rules CEGB. 70 Scuffing cable sheaths installation, 520 Sea water cooling generator transformers. 237 feed pumps electrical services, 834 strainers electrical services, 834 Segregation cables, 429 advanced gas reactor power stations, 436
Subject Index
stations. 430. 543 cabline mdro
power stations, 429 A1 ,tations, 429
sc
mr .cnitades diesel ,..,: enerators. protection, 778 tems in. t18.1 radio seietive canine stems radio communications, 673 Selector sv.itches tccation, 373 Separation cables. 429 Separators recombination cell batteries, 752 Sequential single frequency code signalling Comite Consultatif International de Radio. 681 i
Series reactors case-in-concrete, 276 design. 276-278 , electromagnetically shielded 277 magnetically-shielded cureless. 277 oil-filled. 277 testing, 278 Shaft seal cooling water Bow pumped-storage plant protection, 914 Sheath penetration tests cables, 446 Sheath retraction cable pulling, 519 Sheaths cables. 437 installation, 520 voltage, 458 voltage motor circuits, 473 Short-circuit capability DC switching devices, 414 Short-circuit faults cables, 459 Short-circuit tests switchgear, 336 Short-circuit withstand strength busbars DC switchgear, 414 low voltage switchgear, 391 Short-circuits mechanical transformers, performance, 216 transformers performance, 216 performance, thermal effects, 216 testing, 250 Short-time current tests switchgear, 339 Short-time fireproof cables, 442, 522 application. 491 telephone systems. 663 Shunt opening release circuitry circuit-breakers, 373 Shunt-trip mechanisms voltages, 331 Shutdown controlled electrical systems, 32 electrical systems, 32 station electrical systems load flow analysis, 138 Sideflashing lightning risk assessment, 584 Sidewali pressure cable pulling, 519 . Signal levels control and instrumentation
cables, 476 Signalling dual tone multi-frequency Comite Consultatif International de Telegraphique et Telephonique, 683 Signalling systems radio systems, 681 Silencers diesel generators, 788. 789 Silicon hysteresis loss transformers. 198 Silicone fluids auxiliary transformers insulation. 267 Silver plating generator main connections future trends. 323 Single-frequency simplex fixed station transmitters, 698 Single-phase short-circuit tests circuit-breakers, 339 Siren controllers equipment cubicles, 724 Siren signals nuclear power stations, 729 Siren systems, 722-726 control panels, 723 nuclear power stations, 729 power supplies nuclear power stations, 732 pumped-storage power stations, 741 Sirens power feeds cabling, 491 Site commissioning transformers, 252 Site commissioning tests synchronising schemes, 982 Site emergency warning systems construction sites, 742 Site erection transformers, 251 Sizewell B electrical auxiliaries systems, 19 Slip frequency measurement synchronising, 968 Slip-energy recovery systems, 627 Slipring induction motors, 625-626,803 speed control cranes, 807 Smoke cables fires. 523 detection, 865 extraction. 866 electrical services, 863 Smoke particles weighing cables, fire performance, 527 Smoke tests cables fire performance, 527 Smoothing checks battery chargers, 773 SNUPPS, 19 Sodium hypochlorite production electrical services. 830-834 storage, 834 electrical services, 830-834 water treatment, 837 Soil resistivity earthing systems, 552 measurement, 567 Solenoids
1011
Subject Index
circuit-breakers , de-energising, 379 Sounders paging systems, 666 Source branches power systems computer reliability analysis. definition. 95 Split-type roller bearings f:lectric motors, 636 Sprayssater automatic operation fire fighting. 863 lire fighting electrical services, 863 Sprung channel nuts cable support systems, 496 Squirrel-cage induction motors speed control cranes, 807 starting, 802 Stability power systems computer stability analysis. 183 Stability analysis data output, 186 dynamic data output, 187 power systems computer reliability analysis, 1 73-189 non-linear differential equations, 179 system configuration faults, 184 Stackers coal electrical services, 847 Stairways lighting, 593 Start-up station electrical systems, performance, 29 unit electrical systems, performance, 29 Starting (see also Auto starting; Back to back siarting; Black start) pumped-storage plant
protection, 912.913 Starting transformers pumped-storage plant protection, 912
Static switches protection uninterruptable power supply systems, 64 redundancy uninterruptable power supply systems, 59 surge capability unintemiptable power supply systems, 64 Station Development Particulars, 35 Station electrical systems graphical representation, 93 Station emergency zones siren systems, 722 Station public address systems cabling, 491 Station transformers characteristics, 260 design, 260 electrical auxiliaries systems, 8 neutral earthing, 565 plant bonding, 565 primary voltage electrical systems, economics, 37 protection. 405 pumped-storage plant protection, 912
Stator frames electric motors aluminium, 629 Stator neutral earthing generators, 300
1 012
Stators cooling air over-temperature, pumped-storage plant. protection. 911 generators earth faults, 886-891 earthing, 320 loss of water flow. protection, 901 negative phase sequence, 898 neutral earthing, 320 phase to phase faults, 891-897 turn to turn faults, 897-898 water cooling flow hydrogen, 902 w indings generators, protection, 895 Steam inlet pressures low turbines, protection, 886 Steam inlet temperatures low turbines, protection, 886 Steam turbine-generators generator voltage circuit-breakers synchronising, 982 synchronising, 960,973 speed controls, 960 supplies. 979 voltage controls, 960 Steam/water mixtures quality protection, 871 velocity protection, 871 Steel cold rolled
transformers, hysteresis loss, 198 Steel piles cylindrical ea rill electrodes, 556. 560 sheet earth electrodes, 556, 557 Steelwork cable support systems, 494-512 design, 494 earth rth bonding, 567 cables cleating, 513 open channel steel section cable support systems, 495 structural generator main connections, 314 Step potentials earthing systems cables, 550 Step-down transformers uninterruptable power supply systems, 60 Stopgates pumped-storage plant protection, 914 Storage tanks fuel oil diesel generators, 788 heating, electrical, 857 heating, steam, 857 instrumentation, 858 lightning protection, 583 Stored programme control systems telephone exchanges, 664 Stowger systems telephone exchanges, 664 Strain gauges generator main connections testing, 319 Strainers sea water electrical services, 834 Stress cones 11 kV terminations
Subject Index
core insulation screen. 540 Stuck probability circutt•breakers reliability evaluation, 93 switches reliability evaluation, 93 Substations portable. 415 Subss stern drawing routines power systems reliability evaluation, 92 Suction cone water pumped-storage plant protection, 913 Sulphur hexafluoride insulation transformers, 230 switchgear future trends, 423 Sump pumps controls, 851 Superheierodyning, 701 Switch closing time definition, 950 synchronising, 969 Switch disc onnectors generator voltage protection, 905 generators, 340 transmission voltage synchronising, 962 Switchboards circuit identification, 373 earthing, 368 Low voltage, 403 electrical auxiliaries systems, 8 operating supplies, 332 specialised, 409 switchgear, 332 voltage/time relationships faults. system stability analysis, 185 Switched shunt reactors loss of grid supplies, 33 • Switches (see also Auxiliary switches; Control switches; Earthing switches; Limit switches; Pressure switches; Selector switches; Static switches) critical current tests, 338 definition, 334 remote control emergency supply equipment, 749 stuck probability reliability evaluation, 93 Switchgear, 325-426 3.3 kV construction, 389-391 design. 352-380, 389-391 earthing networks, 565 fused equipment, 380-391 number of phases. 380 operating mechanisms, 390 rated voltage, 380 3.3 kV distribution synchronising, 962 synchronising supplies, 980 11 kV design, 352-380 Plant bonding, 565 11 kV distribution synchronising, 962 synchronising supplies, 980 air-breaks future trends, 421 auxiliaries power systems operational requirements, 327-331 auxiliary contacts, 71 busbars earthing, 368 cable network systems, 485
cabling, 369 certification, 334-340 closing DC systems, 763 co - ordination with fuse protection. 389 coded - key devices, 361
conducting pans identification, 367 construction, 342-352, 357-380 control, 331-332, 353 controlgear gas production plant, 822 current rating, 38 current transformers, 372 DC, 413-414 current making/breaking capability, 414 main connections, battery rooms, 757 short-circuit capability, 414 DC systems control, 765 interlocks. 765 protection, 765 definition. 326 design, 342-352,357-380 disconnection, 361 duty, 390 earthing, 367 earthing networks, 565 electrical services mechanical plant, 804 enclosures, 358 environment, 332 failures future trends, 421 fault studies computer reliability analysis, 166 frequency, 354 future trends, 421 generator main connections testing, 315 generator voltage, 340-352 earthing, 302 low voltage, 391-409 design, 393 maintenance future trends. 422 mechanical plant, 805 metalclad, 358 number of phases. 354 oil-break future trends, 421 operating air plant, 353 performance, 326-327 rated duration of short-circuit, 357 rated normal current, 355 rated peak withstand current earthing circuits, 355 rated short-circuit making current, 384 rated short-time withstand current earthing circuits, 354 rated voltage, 352 short-circuit rating, 38 sulphur hexafluoride future trends, 423 temperature rise tests, 339 testing, 334-340 transmission voltage steam turbine-generators, synchronising supplies, 979 tripping cabling, 430 types, 334-340 vacuum future trends, 422 voltage transformers, 369 withdrawal, 361 Switching automatic power systems, performance analysis, 179
1013
Subject Index
faults power systems, system stability. 183 lighting, 599 power system instability, 176 power systems component active failure, computer reliability analysis. 101 computer reliability analysis, 100 ;urge tests transformers. 250 synchronising, 952 transfonners i mpulse tests, 249 Switching devices 415 V fused feeder circuits, 467 3.3 kV fused feeder circuits, 467 motor circuits, 468 Switching stations communication ?inks, 650 Switching time power systems reliability evaluation, 92 Switchrooms heaters, 599 lighting, 592 Synchronising, 948-986 basic terms, 949-952 controls, 960 diesel generators, 797,974 equipment, 963-974 errors, 953-954 facilities, 958-963 faulty, 954 frequency errors, 954 gas-turbine generators, 973 generators, 952 super-synchronously, 953 switch disconnectors, 341 methods, 955-958 phase errors, 954 steam turbine-generators, 973 supplies, 979 derivation, 974 turbine-generator grid, 31 unit to station, 31 voltage errors, 953-954 Synchronising power, 953-954 Synchronising schemes, 980 site commissioning tests, 982 Synchronising torque. 953-954 Synchronising trolleys, 963 Synchronous generators field currents system stability analysis, 184 field voltages system stability analysis, 184 rotor angles system stability, 183 system stability analysis, 184 system stability analysis, 184 Synchronous machines current decays power systems, computer reliability analysis, 150 rotors mechanical oscillations, power systems, computer reliability analysis, 176 Synchronous motors pulse-width-modulated converters, 628 Synchronous system synchronising, 952 Synchroscopes, 965 System indices evaluation techniques power systems, computer reliability . analysis, 109 GRASP 1 presentation of results, 112
1014
power systems computer reliability analysis, 115-117 System transients power systems computer reliability analysis, 176 Systems neutrals earthing, 554 Tailgates pumped-storage plant protection, 914 Tanks (see also Storage tanks) diesel generators testing, 795 transformers, 225-243 manufacture checks, 244 Tapchangers generator transformers, 253,254 protection, 892 in-tank transformers, 222 off-circuit transformers, 225 single compartment transformers, 222 transformers, 218-225 mechanisms, 221 uses, 218 unit transformers, 262 Tappings transformers, 218-225 Tee-offs generator connections, 300 Telecommunication rooms lighting. 592 Telecommunications, 649-747 accommodation, 652 cabling on-site, 661-663 construction sites, 741-744 DC systems, 766 emergency nuclear power stations, 732 future trends, 744 nuclear power stations, 726-734 power supplies, 652 pumped-storage power stations, 734-741 Telephone exchanges future trends, 745 types, 663 Telephone services British Telecommunications plc, 660-662 Telephone systems sound-powered pumped-storage power stations, 740 Telephones (see also Pay telephones; Radiotelephones) cables ducts, construction sites, 741 direct wire cables, 494 lift cars, 819 plant, 720 requirements. 650 Television interference mechanical plant. electrical services, 805 Telex British Telecommunications plc, 661 construction sites, 744 Temperature see also Ambient temperature detectors, 945 Temperature measurement generator main connections testing, 319 on-load isolated phase busbars, 312-313 Terminal boxes
Subject Index
cabling switchgear, 402 electric motors, 637 Terminals batteries corrosion, 762 Terminated circulators coupling equipment anzennas, 702 Terminations ;see also Cnmped terminations) 1 kV cables, 539-540 bolting power cable fittings, 535 conductors control cables, 537-539 formed power cable fittings. 534 heating and ventilation, 862 moulded rubber electric stress, I I kV cables, 540 power cables conductors, 533-537 wire wrapped control cable conductors, 538 Test devices switchgear, 373 Testing costs generator main connections, future trends, 323 electric motors, 645 generator main connections, 314-318 experience, 318-319 network cable systems, 490 switchgear, 334-340 Thermal ageing insulation cables, 443 Thermal overload protection, 945 Thermal overload relays electric motors protection, 928 Thermal relays characteristics. 933 Thermal resistance cables, 451 buried direct in the ground, 452 in free air, 452 Thermal spacers power cables ladder racks, 513 Thermocouples isolated phase busbars, 313 Thermometers (see also Resistance thermometers; Thermocouples) contact isolated phase busbars, 313 Thermosetting materials cables 11 kV, 438 Thyristor rectifiers battery chargers, 770 Thyristors firing control battery chargers, control boards, 771 Tilting-pad bearings electric motors, 636 Time/current characteristics fuses definition, 412 Total failure rate power systems reliability evaluation, 92 Total project information cable installation, 604 Touch potential earthing systems cables, 550 Toxic gases
emissions cables, fire performance, 530 Trains coal delivery. 843 Transceivers radiotelephones handportable, 711-713 vehicle-mounted, 714 Transferred potential earthing systems cables, 550 Transformers (see also Auxiliary transformers; Control circutt transformers; Current transformers; DC transformers; DC voltage transformers: Excitation transformers; Generator earthing transformers; Generator neutral earthing transformers; Generator transformers; Generator voltage transformers; Instrument transformers; Main transformers; Matching transformers; Rectifier transformers; Reference transformers; Starting transformers; Station transformers; Step-down transformers; Unit transformers; Voltage transformers). 193-286 415 V neutral earthing, 565 3.3 kV neutral earthing, 565 11/3.3 kV ancillary plant bonding. 565 aluminium foil windings, 270 auxiliaries protection, 921-922 basic theory, 196 battery chargers, 768, 770 characteristics, 196-201 compounds layout, 239 construction, 194-253 continuously-transpowed conductor strips construction, 208 core loss, 198 cores construction, 201-205 data load flow analysis, power systems, computer reliability analysis, 145 data entry power systems, computer reliability analysis, 147, 161 design, 194-253 design characteristics equivalent taps, 153 dielectrics, 196 dry-type design, 267 drying out. 244 electrical auxiliaries systems, 7-8 electrochlorination, 834 electrostatic precipitators. 855 final testing, 246 gas production plant, 822 generator main connections testing, 315 generators, 5-6, 299 high voltage windings construction, 209 hot spot temperatures insulation, 216 i mpulse tests, 249 installation, 251-253 insulation sulphur hexafluoride, 230 interconnected star connections, 195 interlock schemes, 72 leakage reactance, .197 load losses, 200 load runs, 250 losses economics, 37 low voltage windings
1015
Subject Index
earthing networks, 566 materials, 196 off-load tapchanger tap positions optimisation, 139 off-load taps representation, power systems, computer reliability analysis, 131 oil dryness, 227 oil-filled fire hazard, 240 on-load tapchangers representation, power systems, computer reliability analysis, 134 outages power systems, computer reliability analysis, 138 overloads protection, 921 power frequency overvoltage tests, 247 processing, 244 quality assurance, 243 reactance fault levels, power systems, computer reliability analysis. 150 short-circuit testing, 250 site commissioning, 252 site erection, 251 special design features, 253-286 star/star connected, 195 substations portable, 415 tanks, 225-243 tapchangers, 218-225 tapping windings construction, 210 tappings, 218-225 tee-off connections generators, 300 tests during manufacture. 244 thermal performance, 250 transport, 251-253 types, 194-195 unintemmtable power supply systems, 62 water cooling, 235 winding conductors construction, 206 transpositions, construction, 208 windings construction, 206 heat production, 213 low voltage, construction, 206 Transient overreaches inverse time relays, 936 Transient recovery voltages generator main connections, 320 power systems performance analysis, 189 Transition resistors tapchangers transformers, 221 Transmission lines lightning transfer windings, testing, 212 Transmission voltages circuit-breakers synchronising, 962 switch disconnectors synchronising, 962 Transmitters fixed stations, 698 network cable systems, 490 quasi-synchronous operation radio communications, 674 radio paging systems, 667 Transport generator transformers, 253 transformers, 251-253 Transpositions
1 016
winding conductors transformers, construction, 208 Travel interlocks lifts, 820 Triaxial cables control and instrumentation, 476 Trip circuit supervision, 915 Trip circuits switchgear control, 331 Trip supply supervision, 915 Tripping schematic diagram, 915 Turbine hall basements cables, 504 Turbine steam valves tripping, 902 Turbine stop valves loss of grid supplies, 33 Turbine-generators operation stability analysis, power systems, 180 reliability, 89 Turbines chimneys lightning, protection systems, 581 data load flow analysis, power systems, computer reliability analysis, 145 lubricating oil cabling, 430 manual trip levers protection, 882 off-load voltage profile, 155 protection. 879-886 start sequence load flow analysis. 140 trips, 880 loss of steam demand, protection, 879 Turbochargers diesel generators, 788 Turn to turn faults generator stators, 897-898 Two-frequency simplex fixed station transmitters, 698 UHF radio cranes control systems, 678 frequencies power stations, 670 on-site nuclear emergencies, 734 UHF systems cf VHF radio systems, 670 Under frequency protection pumped-storage plant, 996 Unidirectional branches power systems computer reliability analysis, definition, 95 Uninterruptable power supply systems, 46-64 components, 59-60 development. 48-49 equipment performance requirement, 62 equipment specification. 60-62 loads, 60 method of operation, 59 motor-generator set schemes, 46 spares philosophy, 60 standby philosophy, 60 static inverter schemes, 46 system configuration, 59 system considerations, 59-60 Unit transformers current, 262
Subject Index
design, 261-263 electrical auxiliaries systems, 7 high set instantaneous overcurrents protect urn. 903 UV inverse time overcurrents protection, 903 i mpedance. 262 internal faults protection, 904 neutral earthing, 565 protection. 902-905 tapchangers, 262 Unioaders barge coal, electrical services, 843 continuous coal, electrical services, 842 User distribution frames telephone cabling, 663 Valve actuators fuel oil storage, 858 water treatment plant electrical services. 842 Valves (see also Air admission valves; Blowclown air admission valves; Draft tube valves; Main inlet valves: Pressure reducing valves; Turbine steam valves; Turbine stop valves) compressed air systems generator main connections, testing, 315 diesel generators, 784 fuel oil diesel generators, 788 power systems performance analysis, 179 Ventilation battery rooms, 757 control gear, 861 electrical services, 861-862 VHF radio cranes control systems. 678 frequencies power stations, 670 off-site nuclear emergencies, 734 VHF radio systems cf UHF radio systems, 670 Viewing ports enclosures isolated phase busbars, 310 Virtual time fuses definition, 412 Visual calling units, 721 Voltage auxiliaries power systems, 326 generator main connections, 304 measurement enclosures, generator main connections, testing. 319 synchronising, 969 switchgear generators, 340-352 Voltage feedback battery chargers control boards, 770 Voltage operating range electrical systems computer reliability analysis, 137 Voltage recovery power systems performance analysis, 177 Voltage regulation cables, 464,468 uninterruptable power supply systems, 59-60 Voltage source converters, 627 Voltage switchgear
generators, 319-320 Voltage transformers accuracy synchronising. 976 cubicles isolated phase busbars, 313 design, 278 interposing synchronising, 976 isolated phase busbars, 309 supplies synchronising, 975 switchgear, 369 synchronising supplies, 974 Voltmeters phase angle synchronising, 965 switchgear low voltage, 405 synchronising, 965 Waisting cable pulling, 519 Wall seals isolated phase busbars, 305 Warning hooters cranes, 817 Warning notices hydrogen production, 826 Water cooling isolated phase busbar, 298 demineralised cooling, isolated phase busbar, 298 Water carryover turbines protection, 883 Water churning pumped-storage plant protection, 913 Water circulating pumps heating and ventilation, 862 Water cooling transformers, 235 Water heating plant electrical services, 862 Water level gauge Hydrastep, 875 Water make-up tanks diesel generators, 786 Water pumps transformers cooling, 239 Water treatment plant electrical control, 840 electrical services, 834-842 power distribution. 838 Waveform analysis battery chargers, 773 Wearing rings cooling water flow pumped-storage plant, protection, 914 Weather isolated phase busbars, 310 Weighing coal train deliveries, 843 Windings (see also Damper windings; Foil windings) aluminium foil transformers, 270 cage induction motors, 624 cage rotors aluminium, 629 conductors transformers, construction. 206 transpositions, transformers, construction, 208
1017
Subject Index
copper manufacture checks, 244 electric motors diamond, 634 hairpin, 634 life, 802 random wound, 634 resin-rich systems. 635 vacuum/pressure impregnation, 635 faults protection, 921 generator stators loss of water flow. protection, 901 protection, 895 turn to turn faults, 897 generators, 299 high voltage transformers, construction, 209 low voltage transformers, construction, 206 split-concentric generator transformers, 253 stationary field pumped-storage plant, heating, protection, 912
1018
stators, 634 aluminium, 629 tappings transformers, construction, 210 transformers construction, 206 disposition, construction, 240 heal production. 213 temperatures. protection, 904 Winds diesel generators protection, 777 Wire brushes power cable fittings preparation, termination connections, 536 Wires single fire tests, 523 Zebedees cable support systems, 4.96 Zig-zag cleats cable support systems, 516
