Training _ Power System Protection _AREVA

TRAINING ON POWER SYSTEM PROTECTION

APPS COMBINED 'COURSE

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INTRODUCTION TO POWER SYSTEM PROTECTON

CONTENTS Overview Of Protection Fundamentals Notes Overcurrent Protection Directional Overcurrnt Transformer Protec:tion Notes Transformer Setting Tutorials Generator and Generator Transf - Protection Generators Setting Criteria Distance Protection Notes Distance Protectiorr Schemes Busbar Protection Motor Protection A C Motor Protection Motor Setting Criteria Notes 1 C T S Notes Additional Analysis Notes Unbalanced Faults Tutorial Balanced Faults Tutorial Grading Examples Tutorials Generator Protection Tutorial C T Selection Tutorial Busbar Protection

Overview Of Protection Fundamentals

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OVERVIEW OF PROTECTION FUNDAMENTALS 1.0

INTRODUCTION

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Relays are compact devices that are connected throughout the power system to detect intolerable or unwanted conditions within an assigned area. They are in effect, a form of active insurance designed to maintain a high degree of service continuity and limit equipment damage. They are "Silent Sentinels". While protective relays will be the main emphasis of this chapter, other types of relays, applied on a more limited basis or used as part df a total protective relays system will also be covered. 2.0

CLASSIFICATION OF RELAYS

Relays can be divided into five functional categories:

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a. P r o t e c t i v e Relays, which detect defective lines, defective apparatus, or other dangerous or intolerable conditions. These relays can either initiate or permit switching or simply provide an alarm.

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b. M o n i t o r i n g R e l a y s , which verify conditions on the power system or in the protection system. These relays include fault detectors, alarm units, channel-monitoring relays, synchronism verification, and network phasing. Power system conditions that do not involve opening circuit breakers during faults can be monitored by these relays.

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c. P r o g r a m m i n g R e l a y s , which establish or detect electrical sequences. Programming relays are used for reclosing and synct-~ronising.

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d. R e g u l a t i n g R e l a y s , which are activated when an operating parameter deviates from predetermined limits. Regulating relays function through supplementary equipment to restore the quantity to the prescribed limits.

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e. Auxiliary Relays, which operate in response to the opening or closing of the operating circuit to supplement another relay or device. These include timers, contact-multiplier relays, sealing units, receiver relays, lock-out relays, closing relays and trip relays. i

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In addition to these functional categories, relays may be classified by input, operating principle or structure and performance characteristic: Input Current voltage Power Pressure Frequency Temperature Flow Vibration (ii)

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Operating Principle of Structure Percentage Multi-restraint Product Solid state Electromechanical Thermal.

and definitions are based on the ANSI Standard The above c~assifi~ation 37.90 (IEEE 313).

3.0

PROTECTIVE RELAYING SYSTEMS AND THEIR DESIGN

Technically, most relays are small systems within themselves. Throughout this chapter, however, the term systems will be used to indicate a combination of relays of the same or different types. Properly speaking, the protective relaying system includes circuit breakers as well as relays. Relays and circuit breakers must function together; there i s little or no value in applying one without the other. Protective relays or systenls are not required to function during normal power system operation, but must be immediately availa,ble to handle intolerable system conditions and avoid serious outages and damage. Thus,. the true operating life of these relays can be on the order of a few seconds, even though they are connected in a system for many years. In practice, the relays operate far more during t.esting and maintenance than in response to'adverse service conditions. -

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In theory, a relay system should be able to respond to the infinity of abnormalities that can possibly occur within the power system. In practice, the relay engineer must arrive at a compromise based on the four factors that influence a n y re!oy rrpp!icatisn: a. Economics - Initial, operating and maintenance. b. Available measure of fault or trouble - Fault magnitudes and location of current transformers and voltage transformers. c. Operating practices - Conformity to standard and accepted practices; ensuring efficient system operation. d. Previous experience - History and anticipation perhaps better expressed of trouble likely to be encountered within-thesystem-. The third and fourth considerations are perhaps better expressed as the "personality of the system and the relay engineer". Since it is simply not feasible to design a protective relaying system capable of handling any potential problem, compromises must be made. In general, only those problems, which according to past experience are likely to occur, receive primary consideration. Naturally, this makes relaying somewhat of an art. Different relay engineers will, using sound logic, design significantly different proteclive systems for essentially the same power system. As a result there is little standardisation in protective relaying. Not only may the type of relaying system vary, but also will the extent of the protective coverage. Too much protection i s almost as bad as little. Nonetheless, protective relaying i s a highly specialised technology requiring an in-depth understanding of the power system as a whole. The relay engineer must know, not only the technology of the abnormal, but have a basic understanding of all the system components and their operation in the system. Relaying, then, i s a "Vertical" specialty requiring a "horizontal" viewpoint. This horizontal, or total system, concept of relaying includes fault protection and the performance of the protection system during abnormal system operation such as severe overloads, generation deficiency, out-of-step conditions, and so forth. Although these areas are vitally important to the relay engineer, his concern has not always been fully appreciated or shared by his colleagues. For this reason, close and continued communication between the planning, relay design, and operation systems should be mandatory, since power systems grow and operating conditions change.

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A complex relaying system may result from poor system design or the economic need to use fewer circuit breakers. Considerable savings can be realized by using fewer circuit breakers and a more complex relay system. Such systems usually involve design compromises requiring careful evaluation, if acceptable protection is to be maintained. -

4.0

DESIGN CRITERIA

The application logic of protective relays divides the power system into several zones, each requiring its own group of relays. In all cases, the five design criteria listed below are common to any well-designed and efficient protective system or system segment: a. Reliability - the ability of the relay p r relay system to perform correctly when needed (dependability) and to avoid unnecessary operalion (security). b. Speed - minimum fault time and equipment damage: c. Selectivity - maximum service continuity with minimum system disconnection. d. Economics - maximum protection at minimum cost. e. Simplicity - minimum equipment and circuitry. Since it is impractical to fully satisfy all these design criteria simultaneously the necessary compromhes must be evaluated on the basis of comparative risks.

4.1 Reliability System reliability consists of two elements - dependability and security. Dependability is the certainty of correct operation in response to system trouble, while security i s the ability of the system to avoid mis-operation between faults. Unfortunately, these aspects of reliability tend to counter one another: increasing security tends to decrease dependability and vice versa. In general, however, modern relaying systems are highly reliable and provide practical compromise between security and dependability. Protective relay system must perform correctly under adverse sysfem and environmental conditions. Regardless of whether other systems are momentarily blinded during this period, the relays must perform accurately and dependably. They must either operate in response to trouble in their assigned area or block correctly i f the trouble is outside their designated area.

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Dependability can be checked relatively easily in the laboratory or during installation by simulated tests or staged faults. Security on the other hand is much more difficult to check. A true test of system security would have to measure response to an almost infinite variety of potential transients and counterfeit trouble indicalions in the power system and its environment. A secure system is usually the result of a good background in design combined with extensive miniature power system testing and can only be confirmed in the power system itself and its environment. 4.2 Speed Relays that could anticipate a fa~lltwo!~ldbe utopian. But, even if 'available, they would doubtlessly raise the question of whether or not the fault gr trouble really required a trip-out. The development of faster relays must always be measured against the increased probability of more unwanted or unexplained operations. Time, no matter how short, is still the best method of distinguishing between real and counterfeit trouble.

Applied to a relay, high speed indicates that the operating time usually does not exceed 50 ms (3 cycles on a 60-hertz base). The term instantaneous indicates that no delay is purposely introduced in the operation. In practice, the terms high speed and instantaneous are frequently used interchangeably. 4.3 Selectivity versus Economics High speed relays provide greater service continuity by reducing fault damage and hazards to personnel. These relays generally have a higher initial cost, which, however, cannot always be justified. Consequently, both low and high-speed relays are used to protect power systems. Both types have high reliability records. Records on protective relay operations consistently show 99.5% and better relay performance.

4.4 Simplicity As in any other engineering discipline, simplicity in a protective relay system is always the hallmark of a good design. The simplest relay system, however, is not always the most economical. As previously indicated, major economies are possible with a complex relay system that uses a minimum number of circuit breakers. Other factors being equal, simplicity of design improves system reliability - if only because there are fewer elements that can malfunction.


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FACTORS INFLUENCING RELAY PERFORMANCE

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Relay performance i s generally classed as:

( 1 ) Correct (2) No conclusion ( 3 ) lncorrect lncorrect operation may be either failure to trip or false tripping. The cause of incorrect operation may be, a) Wrong application, b) lncorrect settings, c ) A personnel error or 4) Equipment mal-function. Equipment that can cause an incorrect operation includes current transformers, voltage transformers, circuit breakers, cable and wiring, relays, channels or station batteries. lncorrect tripping of circuit breakers not associated with the trouble area is often as disastrous as c failure to trip. Hence, special care must be taken in both appiication and installation to ensure against the possibility of incorrect tripping. " No conclusion" is the last resort when no evidence is -available for a correct or incorrect operation. Quite often this is a personnel involvement. 6.0 Zones of Protection The general philosophy of relay application is to divide the power system into protective zones that can be protected adequately with the mininwm amount of the system disconnected. The power system is divided into protective zones for:

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Generators Transformers Buses Transmission and distribution circuits Motors

A typical power system and its zones of protection are shown in Figl. The purpose of the protective system is to provide the first line of protection, within the guide-lines outlined above. Since failures .do occur, however some form of backup protection is provided to trip out the adjace13f breakers or zones surrounding the trouble area. Protection in each zone is overlapped to avoid the possibility of unprotected areas

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The device switching equipment are referred to by numbers, with appropriate suffix letters when necessary, according to the functions they perform. These numbers are based on a system adopted as standard for automatic switchgear by IEEE and incorporated in American Standard C37.2 - 1970. 'This system is used in connection diagrams, in instruction books and in specifications.

8.1 Device Numb'erina Device Number Definition Master Elemenl 1

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Function It is an initiating device, such as a control switch, voltage relay, float switch, etc., which serves either directly or through such permissive devices as protective and time to delay relays. place an equipment in or out of operation. Time Delay It i s a device which functions to give Starting or a desired amount of time delay before or after any point of Closing Relay operation in a switching sequence or protective relaying system, except as specifically provided by device function 48, 62 and 79 1 described later. Checking or It is a device which operates in response to the position of a number Interlocking of other devices (or to a number of Relay predetermined conditions), in an equipment, to allow an operating sequence to proceed, to stop, or to provide a check of the position of these devices or of these conditions i for any purpose. -

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Function It is a device, generally controlled by the device No.1 or equivalent, and the required perrr~issive and protective devices, that serve to make and break the necessary control circuits to place an equipment into operation under the desired conditions and to take it out of operation under other or abnormal conditions. Stopping Device It is a control device used primarily to shut down an equipment and hold it out of operation This device may be manually or Electrically actuated, but excludes the function of electrical lockout (see device 1 function 86) on abnormal conditions. 1 Starting Circuit It is a device whose principal) function is to connect a machine.to Breaker its source of staitina voltaae. I Anode Circuit It is one used in-theanode circuits of a power rectifier for the primary Breaker purpose of interrupting the rectifier circuit if an arc back should occur. Control Power It is a disconnecting device - such as a knife switch, circuit breaker or Disconnecting pullout fuse block, used for the Device purpose of connecting and disconnecting the source of control power to and from the control bus or equipment. Note: Control power is considered to include auxiliary power, which supplies such apparatus as sn~all motors and heaters. It is used for the purpose of reversing Reversing a machine field or for performing 1 Device 1 / any other reversina functions. I ( Unit Sequence ( It is used to change the sequence in 1 which units may be placed in and Switch Definition Master Contactor

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The device switching equipment are referred to by numbers, with appropriate suffix letters when necessary, according to the functions they perform. These numbers are based on a system adopted as standard for automatic switchgear by IEEE and. incorporated in American Standard C37.2 - 1970. This system is used in connection diagrams, in instruction books and in specifications.

8.1 Device Numb'erina Device Number -Definition

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Function Master Element It is an initiating device, such as a control switch, voltage relay, float switch, etc., which serves either directly or through such permissive devices as protective and time delay relays. to place an equipment in or out of operation. Time Delay It is a device which functions to give Stariing or a desired amount of time delay before or after any point of Closing Relay operation in a switching sequence or protective relaying system, except as specifically provided b y device function 48, 62 and 79 described later. It is a device which operates in Checking response to the position of a number ( Interlocking of other devices (or to a number of Relay predetermined conditions), in an equipment, to allow an operating sequence to proceed, to stop, or to provide a check of the position of these devices or of these conditions

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Function It is a device, generally controlled b y the device No.1 or equivalent. and the required permissive and I protective devices, that sr=rL/rs to make and break the rlecessarY control circuits to place art, equipment into operation vrde! 'the I desired ~onditiof?s end to toke i i out of operation ~ n d m TJ~I-!F-: Or abnormal conditic:;~. ____---. Stopping Device It is a coritiol d,-\:jCe usee ;,:irr~arily I to shut down c;;equipn.5~1: arid) . hold it out of oge:2-i&n- -,;rli: C;e/ice i -. may be mancc:ii. or I:5c.::i~~lly , actuated, but exc,,zss ;r,5 f;,..ctior~ 1 of elect!-ical I C ~ ~ - , - 1-, ~ :;edice ~ 5 ' .. I function 86)on c ~ - - ~ .~ ~ = : :.~__ ; ,-T ! C!J T~ I ~ . ~i , lt i s a device .....--zs5 5:ir!.cipaI / Breaker function is to c o ~ - - ~~ ~; ~- ~ vto! ! ~ r its source of stariir:.~-.G ; T C ~ ~ . - . ( . 2i:i of Anode Circuit It is one used in i.-e a power- recjifie- :-r,gy,gr'j ; - ,:- 4:;'l t l ~ e r Breaker purpose oi inte---, ---2 1 circuit if ar: arc F7 :T;~,.J~. Control Power It i s a discanne;- -; ,I. , - ;:,C~I Disconnecting as a knife switc: L-.-=_ - L-3r;/er or Device pullout fuse b!.zqzq - ---the . ; : I d purpose of I:-------, disconnecting ii-5 5 z . - - z-l -' -_,<-,irC~l I power t2 ~ : ; df: I-- -- - - -- - * / r~1.J: or equipr:ie!~i. Note: C ~ r ] i l .PO\.*. ~ / 51 1 -;:;*5? . include zct..rilic-. 1 ... :- ,,.,< ~f-r supplies sctci, r - - - - - -- -- --- *'5~\1 motors a r ~ c nec:~.--,... - - ) it i s used iL7:. :he r*-.-.,2 ...-cs~r~:; Reversing ___ ( Device a mactlifie fiei& -- - :-- ---./-,s - -<,!irtr; an other re\,ersir,z -- -.y .T; : Unit Sequence It is used :p , - ~ ? C ~-. -- . Z--.- _ - s - - - :=- 'c. irl which ur;i;- _ -,?c.,v - _ -- -- - -,-'"; '

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Device Number 25

Definition Function Synchronising or It is a device that operates when Synchronismtwo ac circuits are within the desired limits of frequency, phase angle and Check Device voltage, to permit' or to cause the paralleling of these two circuits. It is a device, which functions when Apparatus Thermal Device the temperature of the shunt field or the armature winding of a machine, or that of a load limiting or load shifting resistor or of a liquid or other medium exceeds a p.redefermined value ; or if the temperature of the protected appa~.atus, such as a power rectifier, or of any medium decreases below a predetermined value. I Under Voltage It is a device, which functions on a Relay given value 'of undervoltage. Flanie detector It is a device that monitors the presence of the pilot or main flame -In such apparatus as a gas turbine or a steam boiler. 1 It is a device used for disconnecting Isolating one circuit from another for the ( Contcctor purposes of emergency operation, maintenance, or test. It is a non-automatically reset Annunciator relay device that gives a number of separate visual indications upon the functioning of protective devices and which may also be arranged to perform a lockout function. It connects a circuit such as the Sepcrzlte shunt field of a synchronous Excitciion converter, to a source of separate Device excitation during the starting sequence ; or one which energises the excitation and ignition circuits of a nower rectifier.

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Function I desired value of power fiow in given direction, or upon reverse power, like resulting from arc back in the anode or cathode circuits of a I power rectifier. Position Switch It makes or breaks contact when the 1 main device or piece of apparatus, 1 which has no device function number, reaches a given position. It is a device such as a motorMaster operated multi-conjact switch, or Sequence Device the equiv'alent, or a programming device, such 0 s a computer, that establishes or determines the operating sequence of the major devices in an equipment during starting and stopping or during other sequential operations. It is used for raising, lowering, or Brushor ] shifting, the brushes of a machine, or I Operating, for short circuiting its slip rings, or for Slip-ring-shortengaging or disengaging the circuiting contacts of a mechanical rectifier. Device Polarity or It operates or permits the operation a, of another device on Polarising Voltage Device predetermined polarity only verifies the presence of a polarising voltage in an equipment. Undercurrent or It functions when the current or Under power power flow decreases below a predetermined value. 1 Relav It functions on excessive bearing Bearing temperature, or on other abnormal Protective mechanical conditions, such as Device undue wear, which may eventually result in excessive bearing Definition Power Relay

Mechanical Condition Monitor -

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Definition

Function associated with bearings as covered under device function 38), such as excessive vibration, eccentricity, expansion, shock, tilting, or seal failure. It functions on a given or abnormally Field Relay low value or failure of machine field current, or on an excessive value of the reactive component of armature current in an ac machine indicating abnormally low field excitation. Field Circuit It is a device, which functions to Breaker apply, or to remove the field excitation of a machine. 42 function is to connect a machine to Breaker its source of running or operating voltage. This function may also be used for a device, such as a contactor, that is used in series with 1 a circuit breaker or other fault protecting means, primarily for frequent opening and closing of the circuit. Manual Transfer It transfers the control circuits so as Selector to modify the plan of operation of Device transfers the switching equipment or of some of the devices. Unit Sequence It is a device, whichfunctions to start the next available unit in a multipleStarting Relay unit equipment on the failure or on. I ( the non-availability of the normally 1 I I preceding unit. It is a device that functions upon the I Atmospheric I Condition occurrence of an abnormal atmospheric condition, such as Monitor damaging fumes, ex'plosive mixture, smoke or fire. 46 I Reverse-Phase. It is a relav which functions when the 1 . .

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Definition Phase-Balance, Current Relay

Function poly-phase currents are of reverse phase sequence, or when the polyphase cu:cer?,?s fire vnbolonced zl; contain negative phase-sequence components above a given amount. Phase - It functions, upon a predetermined 1 Sequence - 1 value of poly phase voltage in the ] Voltage Relay desired phase sequence. It is a relay that generally returns the Incomplete Sequence Relay equipment to the normal, or off, position and locks it out if the normal starting, operating or stopping sequence is not properly completed within a predetermined time. If the device is used for alarm purpose only, it should preferably be , designated as 48A (alarm). or It is a relay that functions w.hen the temperature of a machine Transformer, armature, or other -load carrying Thermal Relay winding or element of a machine, or the temperature of a power rectifier or power transformer (including a power rectifier transformer) exceeds an medetermined value. Ilnstantaneous [ I t is a relay that functions1 overcurrent, or instantaneously on an excessive Rate of rise value of current, or on an excessive current rise, thus indicating a fault in Relay the apparatus or circuit being protected. AC Time It is a relay with either a definile or an inverse time characteristic lhat Overcurrent functions when the current in an ac Relay circuit exceeds a predetermined value. I AC Circuit It i s a device that is used to close I Breaker and interrupt an ac power circuit under normal conditions or to

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Function 1 associated with bearings as covered under device function 38), such as excessive vibration, eccentricity, expansion, shock, tilting, or seal failure. It functions on a given or abnormally Field Relay low value or failure of machine field current, or on an excessive value of the reactive component of armature current in an ac machine indicating abnormally low field excitation. Field Circuit It i s :a device, which functions to apply, or to remove the field Breaker Definition

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Circuit It is a device whose principal function i s to connect a machine to ( its source of running or operating voltage. This function may also be used for a device, such as- a contactor, that is used in series with a circuit breaker or other fault protecting means, primarily frequent opening and closing of the circuit. Manual Transfer It transfers the control circuits so as or Selector to modify the plan of operation of Device transfers the switching equipment or of some of the devices. 1 Unit Sequence It is a device, which functions to start the next available unit in a multipleStarting Relay unit equipment on the failure or on 1I 1 the non-availability of the normally 1 I

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atmospheric condition, such damaging fumes, explosive mixture, smoke or fire. lt is a reiay which functions when the

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Device Number

47

Function poly-phase currents are of reverse phase sequence, or when the polyphclse currents me unbalaficzd o i contain negative phase-sequence cornponents above a given amount. It functions upon a predetermined value of poly phase voltage in the desired phase sequence. Volta e Rela It is a relay that generally returns the Incomplete Sequence Relay equipment to the normal, .or off, position and locks it out i f the normal starting, operating or stopping sequence is not properly completed within a predetermined time. If the device is used for alarm purpose I I I only, it should preferably be / I designated as 48A {alarm). Machine, or It i s a relay that functions when the temperature of a machine Transformer, armature, or other load carrying Thermal Relay winding or element of a machine, or the temperature of a power rectifier or power transformer (including a power rectifier transformer) exceeds an predetermined value. It is a relay that functions Instantaneous overcurrent, o i instantaneously on an excessive Rate of rise value of current, or on an excessive current rise, thus indicating a fault in , Relay the apparatus or circuit being ~rotected. Time / It i s a relay with either a definile or AC an inverse time characterisiic l l m t Overcurrent functions when the current in an ac Relay ( circuit exceeds a predetermined value. AC Circuit It is a device that is used to c:lose 1 and interrupt an ac power circuit Breaker under normal condilions or to Definition Phase-Balance, Current Relay

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Device Number

Definition

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Function mechanical positioning. AC directional It is a relay that functions on a Overcurrent desired value of ac overcurrent Relay I flowing in a predetermined I direction. Blocking Relay It is a relay that initiates a pilot signal for blocking of tripping on external faults in a transmission line or in other apparatus under predetermined conditions, or co-ordinates with other devices to block tripping or to block re-closing on an out-of-step condition or on powerswing:. ermissive It is - generally a two position, ! Control ~ e v i c e ' manudlly operated switch that in one position permits the closing of a circuit breaker, or the placing of an equipment into operation, and in the other posilion prevents the circuit breaker or the equipment from being operated. ! It is a variable resistance device I Rheostat used in an electric circuit, which is electrically operated or has other electrical accessories, such as I 1 auxiliary position or limit switches. I It is a switch which operates on 1 Level switch ! given values, or on a given rate of 1 change, of level. I DC circuit It is used to close and interrupt a dc power circuit under normal Breaker conditions or to interrupt this circuit 1 under fault or emergency conditions. i Load - Resistor It is used to shunt or insert a step of load limiting, shifting, or indicating ' Contactor resistance in a power circuit, or to I switch a space heater in circuit, or to switch a light, or regenerative load resistor of a power reclifier or I '

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Device Number

Definition

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Function other machine in and out of circuit. It i s a device other than the annunciator, as covered under device No.30, which is used to operate in connection with a visual

Alarm ~ e b y

that isused for moving a muin device from one position to another i n a n equipment ;as . for example, shifting a removable circuit breaker unit to and from the connected, disconnected, and test positions. DC Overcurrent It is a relay that functions when the current in a dc circuit exceeds a Relay aiven value. Pulse Transmitter It i s used to generate and transmit I pulses over a telemetering or pilotwire circuit to the remote indicating or receiving device. Angle It is a relay that funclions at a phase angle ",n r:i'g, or predetermined between two voltages or between out-of-ste-) two currents or between voltage Protective

Changing Mechanism

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Relay

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0Flow Switch

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that controls automatic reclosing and locking out

It is a switch, which operates on on a given rate of I I change, of flow. It is a relay that functions on a ~iequency predetermined value of frequency, Relay either underlover on normal system frequency or rate of , change of frequency. 1 It i s a relay that controls the DC Re-closing 1 automatic closing and reclosing of a ( Relay dc circuit interrupter, generally in resoonse to load circuit conditions.

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Device Number

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Definition

Function mechanical positioning. 1 AC directional It is a relay that functions on a Overcurrent desired value of ac overcurrent ( Relay flowing in a predetermined direction. I Blocking Relay It is a relay that initiates a pilot signal for blocking of tripping on external faults in a transmission line or in other / apparatus under predetermined conditions, or co-ordinates with ! other devices to block tripping or to block re-closing on an out-of-step ! condition or on po\der swings: 1 Permissive It is generally a two position, i Control Device manually operated switch that in one position permits the closing of a circuit breaker, or the placing of an equipment into operation, and in the other position prevents the I circuit breaker or the equipment I from being operated. It is a variable resistance device I Rheostat used in an electric circuit, which is electrically operated or has other electrical accessories, such a: auxiliary position or limit switches. It is a switch which operates or i Level Switch given values, or on a given rate of change, of level. I DC circuit It is used to close power circuit under normal 1 Breaker I conditions or to interrupt this circuit under fault or emergency conditions. : Load - Resistor It is used to shunt or insert a step of load limiting, shifting, or indicating Contactor I I resistance in a power circuit, or to switch a space heater in circuit, or to switch a light, or regenerative load resistor of a power rectifier or i I

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OALSTOM Limited, inergy Automation & Information

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APPS- Combined course

Device Number 74

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Function other machine in and out of circuit. It is a device other than the Alarm ~ e l a y annunciator, as covered under device No.30, which i s used i o operate in connection with a visual or audible alarm. It is a mechanism that i s used for Position moving a main device from one Changing position to another in an equipment Mechanism ;as for example, shifting a removable circuit breaker unit to and from the connected, disconnected, and test posilions. DC 0ve:current It is a relay that functions when the l current in a dc circuit exceeds a i given value. Pulse Transmitter It is used to generate and transmit pulses over a telemetering or pilotwire circuit to the remote indicating or receiving device. I Phase Angle It is a relay that functions at a phase angle Measuring, or predetermined between two voltages or between out-of-step two currents or between voltage Protective and current. Relay AC Re-closing It is a relay that controls the automatic reclosing and locking out Relay of an ac circuit interrupter. It is a switch, which operates on Flow Switch given values, or on a given rate of change, of flow. It is a relay that functions or-) a ~tequenc~ predetermined value of frequency, Relay e~therunderJover on normal system frequency or rate of change of frequency. DC Re-closing It is a relay that controls automatic closing and reclosing of a Relay dc circuit inter~upter,generally in response to load circuit conditions. Definition

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OALSTOM Limited, Energy Automation & information

APPS- Combined course Overview Of Protection Fundamentals Page 24 oi 6

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Device Number

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Definition to 94 i s suitable.

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Function

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8.2 Devices Performing Than One Function If one device performs two relatively important functions in an equipment so that it is desirable to identify both of these functions, this may be done by using a double function number and name such as: 50/51 - Instantaneous and Time Overcurrent Relay. 8.3 SuffixNumbers If h.10 or more devices with the same function number and suffix letter (if used) are present in the same equipment, they rlay be distinguished by numbered suffixes as for example, 52X-1, 52X-2 and 52X-3, when necessary.

8.4 Suffix Letters Suffix letters are used with device function numbers for va~~ious purposes. In order to prevent possible conflict each suffix letter should have only one meaning in an individual equipment. All other words should use the abbreviations as contained in ANSI Y 1.1 latest revision, or should use some other distinctive abbreviation, or be written out in full each time they are used. The meaning of each single suffix letter, or combination of letters, should b e clearly designated in the legend on the drawings or publications applying to the equipment. Lower case (small) suffix letters are used in practically all instances on electrical diagrams for the auxiliary, position, and limit switches. Capital letters are generally used for all other suffix letters. Th,e letters should generally form part of the device function designation, are usually written directly after the device function number, as for example, 52CS. 71 W, or 49D. When it is necessary to use two types of suffix letters in connection with one function number, it is often desirable for clarity to separate them by a slanted line or'dash, as for example, 20D/CS or 2OD-CS. . The suffix letters which denote parts of the main device, and those which cannot or need not form part of the device function designation, are generally written directly below the device function number on drawings, as for example, 52/CC or 43/A. -

8.9

Standard reference positions of some typical devices


APPS- Combined course Overview Of Protection Fundamentals Page 250f 0

Device Power Circuit Breaker Disconnecting Switch Load-break swiich Valve Gate Clutch -

Rheostat Adjusting Means Relay (2) Contactor (21 Contactor (latched-in-type) Temperature Relay (3) Level Detector (3) Flow Detector (3) Speed Switch (3) Vibration Detector (3) 1 Pressure Switch 131 ) Vacuum Switch (3) 7

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Standard Reference Position Main Contacts Open Main Contacts Open Main Contacts Open Closed Posilion ) Closed Posilion Disengaged Position Disengaged Position Maximum Gap Position Maximum resistance Position Position De-energised Position Mairi Contacts Open Lowest Temperature Lowest Level Lowest Flow Lowest Speed Minimum Vibration I Lowest Pressure 1 Lowest Pressure i.e., Highest Vacuum

Note : If several similar auxiliary switches are present on the same device, they should be designated numerically 1.2.3etc, when necessary. ( 1 ) 'These may be speed, voltage, current, load, or similar adjusting devices comprising rheostats, springs. levers, or other components for the purpose.

( 2 ) These electrically operated devices are of the non-latched-in type, whose contact p,osition is dependent only upon the degree of energisation of the operating or restraining or holding coil or coils which may or may not be suitable for continuous energisation. The de-energised position of the device i s that with all coils deenergised. (3) The energising influences for these devices are considered to be, respectively, rising temperature, rising level, increasing flow, rising speed, increasing vibration, and increasing pressure.

The simple designation "a" or "b" is used in all cases where there is no need to adjust the contacts to change position at any particular point in the travel of the main device or where the part of the travel, where the contacts change position is of no significance in the control or operating scheme. Hence fhe "a" or "b" designations usually are sufficient for circuit breaker auxiliary switches. OALSTOM Limited, Energy .4utomation & Information

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APPS- Combined course

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Device Number

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Overview Of Protection Fundamentals Page 24 oi O

Definition to 94 is suitable.

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Function

8.2 Devices Performing ~ 6 r Than e One Funciion If one device performs two relatively important functions in an equipment so that it i s desirable to identify both of these functions, this may be done by using a double function number and name such as:

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50151 - Instantaneous and Time Overcurrent Relay. 8.3 Suffix Numbers If two or more devices with the same-function number and suffix letter (if used) are present in the same equipment, they may be distinguished by numbered suffixes as for example, 52X-1, 52X-2 and 52X-3, when necessary. 8.4 Suffix Letters Suffix letters are used with device function numbers for various purposes. In order to prevent possible conflict each suffix letter should have only one meaning in an individual equipment. All other words should use the abbreviations as contained in ANSI Y 1 . l latest revision, or should use some other distinctive abbreviation, or be written out in full each time they are used. The meaning of each single suffix letter, or combination of letters, should be clearly designated in the legend on the drawings or publicalions applying to the equipment.

Lower case (small) suffix letters are used in practically all instances on electrical diagrams for the auxiliary, position, and limit switches. Capital letters are generally used for all other suffix letters. The letters should generally form part of the device function designation, are usually written directly after the device function number, as for example, 52CS, 71 W, or 490. When it is necessary to use two types of suffix letters in connection with one function number, it is often desirable for clarity to separate them by a slanted line or'das!?,as for example, 20DJCS or 20D-CS. The suffix letters which denote parts of the main device, and those which cannot or need not form part of the device function designation, are generally written direcily below the device function number on drawings, as for example, 52lCC or 43lA. -

8.9

Standard reference positions of some typical devices i

OALSTOM Limited, Energy ~utomatidn& Information

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Device

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Standard Reference Position Main Contacts Open Main Contacts Open Main Contacts Open Valve Closed Position Closed Position Gate I Disengaged Position Clutch Disengaged 'Position Turning Gear Power Electrodes Maximum Posilion Maximum resistance Posilion Rheostat Low or Down Position Adjusting Means ( 1 ) De-energised position Relay (2) Contactor (2) De-energised Position . Contactor (latched-in-type) Main Contacts Open Lowest Temperature Temperature Relay ( 3 ) I Level Detector 131 ! Lowest Level 1 Lowest Flow Flow Detector (3) Lowest Speed Speed Switch (3) Minimum Vibration Vibration Detector (3) Lowest Pressure Pressure Switch (3) 1 Lowest Pressure i.e., Highest Vacuum Vacuum Switch (3)

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Note : If several similar auxiliary switches are present on the same device, they should be designated numerically 1,2,3 etc, when necessary.

( 1 ) These may be speed, voltage, current, load. or similar adjusting devices conlprising rheostats, springs, levers, or other components for the purpose.

(2) These electrically operated devices are of the non-latched-in type, whose contact position is dependent only upon the degree of energisation of the operating or restraining or holding coil or coils which may or may not be suitable for continuous energisation. The de-energised position of the device is that with all coils deenergised.

(3) The energising influences for these devices are considered to be, respectively, rising temperature, rising level, increasing flow, rising speed, increasing vibration, and increasing pressure.

The simple designation "a" or "b" is used in all cases where there is no need to adjust the contacts to change position at any particular point in the travel of the main device or where the part of the travel, where the contacts change position is of no significance in the control or operating scheme. Hence fhe "a" or "b" designations usually are sufficient for circuit breaker auxiliary switches. OALSTOM Limited, Energy .4utomation & Informalion -

APPS- Cornbined course Overview Of Pr~:ec:Icn Fundamentals Page 28 of 0

The following Chart gives a birds-eye view of the relay classifications based on technology.

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Relays I

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Electromechanical

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-+ Analogue

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Numerical

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TYPES OF PROTECTION FUSES The simplest form of overcurrent protection is the fuse. The fuse is capable of operating in less than 10ms for very large values of current, thus considerably limiting fault energy. However, it does have a number of disadvantages, namely; Can be difficult to co-ordinate Its characteristic is fixed Needs replacing ioiiowing iauit ciearance Has limited sensitivity to earthfaults since it is rated above the full load current of the feeder Operation of single fuse results in a condition refereed to as single phasing. Single phasing .can be disastrous for rotating plant such as motors. The fuse characteristic is split into two sections, the 'Pre-arcing Time' and the 'Arcing Time'. The addition of these times is referred to as the 'Total Operating Time'.

Fault

PRINCIPLE OF OVERCURRENT PROTEClION The purpose of overcurrent protection, as with other forms of protection, is to detect faults on a power system and as a result, initiate the opening of switchgear in order to isolate the faulty part of the system. The protection must thus be discriminative, that is to say it shall, as far as possible, select and isolate only the faulty part of the system leaving all other parts in normal operation. Discrimination can be achieved by overcurrent, or by time, or by a combination of overcurrent and time.

DISCRIMINATION BY CURRENT Discrimination by current relies upon the fact that the fault curren't varies with the position of the fault. This variation is due to the impedance of various items of plant, such as cables and transformers, between the source and the fault. Relays throughout the system are set to operate at suitable values such that only the relay nearest to the fault operates. of operation are generally termed Instantaneous Relays which adopt this overcurrent relays. (Where the fault level does not vary greatly between two relay location then the use of i n s t a n t a n e ~ sovercurrent relays is not possible). DISCRIMINATION BY TIME Page 1

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If the fault level over a system is reasonably constant then discrimination by current will not be possible. An alternatlile Is tc use time discrimination in which each overcurrent relay is given a fixed ?irr?edelay with the relay farthest away from the source having the shortest time delay. Operating time is thus substantially,independent of fault level but the main disadvantage is that the relay nearest the source will have the longest time delay and this is the point with the highest fault level. Relays which adopt this principle of operation are generally termed definite (independent) time overcurrent relays. NOTE : When applying definite time overcurrent relays care must be taken to ensure that the thermal rating of the current measuring element is not exceeded.

(Relay Current Setting)

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D1SCRIMlNATlON BY BOTH TlME AND CURRENT Due to the limitat~onsimposed by the independent use of either t ~ m eor current, the inverse time overcurrent characteristic has been developed. With this character~st~c the time of operation is inversely proportional to the current applied, i.e.; basically the higher the current applied, the faster the relay operates. Thus, the actual characteristic IS a function of both t ~ m eand current settings, thereby gaining the advantages of the previous mentioned methods and eliminating some the disadvantages.

TlME

IS (Relay Current Setting)

Applied Current'

PRINCIPLES OF CO-ORDINATION The principle of co-ordination refers to the procedure of setting overcurrent relays to ensure that the relay nearest the fault operates first and all other relays have adequate additional time to prevent them from operating. If the relay nearest fo the fault fails to clear the fault, and the co-ordination is correct, then the next up-stream relay should operate and so on towards the source, thus isolating the minimum amount of plant. The principle of co-ordination is often referred to as 'grading'. When performing any co-ordination exercise the following need to be considered: Relay Characteristics Relay Current Setting Grading Margin Time Multiplier Setting -

Relay Characteristics There are numerous characteristics, however they all confirm to either BS142lIEC or ANSIIIEEE standards. The BS142lIEC standard incorporates the following characteristics. Standard Inverse Very lnverse Extremely Irlverse Long Time Inverse The ANSIIIEEE standard incorporates the following characteristics: Moderately InverseVery lnverse Extremely lnverse Short Time lnverse Inverse The BS142lIEC standard curves are mainly adopted in the LIK and the most commonly used ones are explained in more detail below: Standard lnverse - This characteristic is commonly known as the 3110 characteristic, i.e. at ten times setting current and TMS of 1 the relay will operate in 3 secs. The characteristic curve can be defined by the mathematical expression :

where I 15

111,

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applied current setting current multiple of setting current

The standard inverse time characteristic is widely applied at all system voltages - a s back up protection on EHV systems and as the main protection on HV and MV distribution systems.

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In general, the standard inverse characteristics are used when There are no co-ordination requirements with other types of protective equipm2nt further out on the system, e.g. Fuses, thermal characteristics of transformers, motors etc. The fault levels at the near and far ends of the system do not vary significantly. Page 3

There is minimal inrush on cold load pick up. Cold load inrush is that c u i e n t which occurs when a feeder is energised after a prolonged outage. In general the relay cannot be set above this value but the current should decrease below the relay setting before the relay operates.

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Very lnverse Time This type of characteristic is normally used to obtain greater time selectivity when the limiting overall time factor is very low, and the fault current at any point does not vary tno :vlde!y with system conditions. It is particularly suitable, if there is a substantial reduction of fault current as the distance from the power source increases. The steeper inverse curve gives tonger time grading intervals. Its operating time is approximately doubled for a reduction in setting from figures 7 to 4 times the relay current setting. This permits the same time multiplier setting for several relays in series. The characteristic curve can be defined by the mathematical expression : t =

13.5

-

{i: I] -

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Extremely lnverse Time With this characteristic the operating time is approximately inversely proportional to the square of the current. The long operating time of the relay at peak values of load current make the relay particularly suitable for grading with fuses and also for protection of feeders which are subject to peak currents on switching in, such as feeders supplying refrigerators, pumps, water heaters etc., which remain connected even after a prolonged interruption of supply. For cases where the generation is practically constant and discrimination with low tripping times is difficult to obtain, because of the low impedance per line section, an extremely inverse relay can be very useful since only a small difference of current is necessary to obtain an adequate time difference.

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Another application for this relay is with auto reclosers in low vo'ltage distribution circuits. As the majority of faults are of a transient nature, the relay is set to operate before the normal operating time of the fuse: thus preventing perhaps unnecessary blowing of the fuse. Upon reclosure, if the fault persists, the recloser locks itself in the closed posjtion and allows the fuse to blow to clear the fault. This characteristic is also widely used for protecting plant against overheating since overheating is usually an I,t function.

Page 4

This characteristic curve can be defined by the mathematical expression :

t =

80

{ti' -

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b o n g Time Inverse This type of characteristic has a long time characteristic and may be used for protection of neutral earthing resistors (which normally have a 30 sec rating). The relay operating time at 5 times current setting is 30 secs at TMS of 1. This can be defined by :

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Current Setting The current setting of a relay is typically described aS either a percentage or multiple of the current transformer primary or secondary rating. If the CT primary rating is equal to the normal full load current of the circuit then the percentage setting will refer directly to the primary system. This is an important point as if, for example, the normal primary full load current was, say, 400 amp but the CT ratio was 50015 then a relay with setting range 50-200% of 5 amp set at 100% would not represent a "full load" setting;-the actual setting would in fact be 125% of full load current. The choice of current setting thus depends on the load current and the CT ratio and is normally close to but above the maximum load current (typically'lO%) - assuming of course the circuit is capable of carrying the maximum foreseeable load. It should be stressed at this point, that the relay is neither designed nor intended to be used as an overload relay but as a protective relay to protect the system under fault conditions. It is also important to consider the resetting of the relay. The relay will reset when the current is reduced to 90%-95% of the setting (Depending on relay design) and if the normal load current is above this value the relay will not reset after starting to operate under through fault conditions which are cleared by other switchgear. The setting for a typical overcurrent relay with a reset ratio of 95% can be determined using the following:

Where:

Is = Setting IF^ = Full Load Current

Grading Margin As previously mentioned, to obtain correct discrimination it is necessary to have a time interval between the operation of two adjacent relays. This time interval or grading margin depends upon a number of factors : The circuit breaker fault interrupting time a) The overshoot time of the relay b) C) Errors Final margin on completion of operation (safety margin) d) The discriminating relay can only be de-energised when the circuit breaker has completely interrupted the fault current. It is now normal practice to use a value of 50 Page !

100 ms for circuit breaker overall interrupting time but obviously if it is known that the switchgear is slower than this time, this must be taken..injo account.Operating of the relay may continue for a short time after the relay is de-energised until a n i stored energy is dissipated. For example, an induction disc 'element will have stored kinetic energy (or inertia) and a numerical relay may have stored energy in capacitors. Although these factors are minimised by design, some allowance is usually necessary. It is common to use a figure of 50 ms. NO-TE:

Travel

The overshoot time is not the actual time during which some forward operation takes plan but is the time that the relay would have taken to travel the same distance had the relay remained energised.

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Overshoot Travel

t l = relay de-energised t3 - t l = actual overshoot time t2 - t l = overshoot time used in the calculation of margin

tl

t2

t3

All measuring dev~cessuch as rejays and current transformers are subject to some degree of error The t ~ m echaracteristic of either or both of the relays involved may have positive or negat~veerrors. Current transformer errors are mainly due to the rnagnetis~ngcharacteristic. It should be noted the CT errors do not affect definite time overcurrent relays. A safety margin of 100 ms is normally added to the final calculated margin to ensure correct discrirn~nation.This additional time ensures a satisfactory contact gap (or equivalent) is maintained. In the past, a fixed margin of 0-4 secs was considered adequate for correct discrimination. With faster modern switchgear and lower overshoot times a figure of 0.35 secs is quite reasonable and under the best possible conditions 0-3secs may be feasible. However, rather than using a fixed margin it is better to adopt a fixed time for circuit breaker operation and relay overshoot and add to this a variable time value which takes into account relay and CT errors and the safety margin. This is particularly so when grading at low values multiples of setting current where the relay operating time is longer and a fixed total margin may be of the same order as the relay timing error. A fixed value 0-25 secs is chosen which is made up of 0.1 secs for circuit breaker operating time. 0.05 secs for relay overshoot time and 0.1 sec for safety margin.

In considering the variable time value, it is assumed that each IDMT relay complies with basic assigned error class 7.5 according to British practice in BS 142. The error for a class 7.5 relay IS 5 7.5%, but allowance should be made for the effects of temperature, frequency and departure from the reference conditions as laid down in the BS. A more practical approximation is to assume a total effective error of 2 x 7-5 i.e. 15% and is to apbly to the relay nearest the fault which'is considered slow. To this total effective relay error a further 10% is added to allow for overall CT error. Page 6

Thus it is proposed to adopt the following equstior: ,:t determine the grading margin between IDMT relays : t'

=

0.25 + 0-25 secs

where t = 'normal operating time of relay nearest the fault

As far as definite time overcurrent relays are concerned, the fixed value will remain the same but the relays are assumed to comply with error class 10 i.e. 10%. For the reasons stated .previously, a practical approximation is to assume a total effective error of 20% with the relay nearest the fault considered slow. As previously stated, CT errors will have little effect of the operating time, thus it is proposed to adopt the equation :

+

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t'

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0.25 + 0.25 secs

For the majority of systems an overcurrent grading exercise can be performed quite adequately using a fixed margin of 0.4 secs. It is only when a number of stages are involved and difficulties are being encountered that it may become necessary to invmtigate margin times in more detail. To summarise, each system is different and should be treated as so, it is not possible to lay down rigid rules regarding grading margins and every grading exercise will ultimately be a compromise of some form. Grading Overcurrent Relays With Downstream Fuse For some applications ~twill be necessary to grade overcurrent relays with fuses. When the fuse is downstream of the relay the following formula can be used to calculate the grading margin.

-1 I

Grading Margin = 0.4Tf + 0.1 5s over the whole characteristic. The above formula assumes a minimum fuse operating time of 0.01 seconds Generally for this type of application a Extremely Inverse characteristic should be chosen to grade with the fuse and the current setting of the relay should be 3 - 4 x rating of fuse to ensure co-ordination.

Time Multiplier Setting The time multiplier setting is a means of adjusting the operating time of an inverse type characteristic. It is not a time setting but a multiplier. In order to calculate the required TMS (Treq), calculate the operating time of the'nearest downstream protection device at the maximum fault level seen by both devices, add to this the grading margin, calculate the operating time of the upstream device at this fault level with a TMS equal to one (TI) and then use the following for formula:

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TMS = Treq 1 T I Plotting Of Characteristic It is convenient to show the standard inverse time characteristic on logllog graph paper with the 'y' axis scaled in seconds and the"x' axis in terms of "multiples of current setting". By doing this the characteristic can be applied to any relay, irrespective of setting range and nominal rating.

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HIGH SET OVERCURRENT

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Where the source impedance is small in comparison with the protected circ~lit.i.mped.ance,. . the use of high set instantaneous overcurrent units can be advantageous (for example on long transmission lines or transformer feeders).

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The application of an instantaneous unit makes possible a reduction in the tripping time at high fault levels and also allows the discriminating curves behind the high set unit to be lowered thereby improving overall system grading. i i is important io note iiiai when grading with the relay immediately behind the high set units, the grading interval should be established at the current setting of the high set unit .and not at the maximum fault level that would normally be used for grading IDMT relays. When using high set units it is important to ensure that the relay does not operate for faults outside the protected section. The relays are normally set at 1.2 - 1.3 times the maximum fault level at the remote end of the protected section. .This particularly applies when using instantaneous units on the HV side of a transformer when the instantaneous unit should not operate for faults on the LV side. , The 1-2- 1.3 factor allows for transient overreach, CT errors and slight errors in transformer impedance and line length.

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Transient overreach occurs when the current wave contains a dc component. Although a relay may have a setting above the rms value of current, the initial peak value of current due to the dc offset may be sufficient to operate the relay, if it has high transient overreach. Percentage transient overreach is defined as

11-12 12

x

?OO

Where : I1 12

= =

relay pick-up current in steady state rms amps rms value of current which when fully offset will just pick up the relay

Modern Relays have integral instantaneous elements which have low transient overreach. The degree of transient overreach is normally affected by the time constant of the measured fault current. For example, a typical transient overreacn of a numerical overcurrent relay is less than 5% for time constants up to 30 ms and less than 10% for t ~ m econstant up to 100 ms. This allows the instantaneous elements to be used as h ~ g h set un~tsfor application to transformers and long feeders. The low'transient overreach allows settings to be just above the maximum fault current at which discrimination IS required. The instantaneous elements are also suitable for use as low set elements in conlunction with auto-reclose on distribution systems

EARTH FAULT PROTECTION

Earth faults, which are by far the most frequent type of fault, will be detected by phase overcurrent units as previously described but it is possible to obtain more sensitive protection by utilising a relay which responds only to the residual current in a system. Residual (or zero sequence) current only exists when a current flows to earth. The residual current can be detected either by connecting a CT in an available neutral to earth connection or by connecting Ilne CT's in parallel. By using this parallel connection the earth fault relay is completely unaffected by load currents whether balanced or unbalanced. The parallel connection can be extended to include either two or three Page 8

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overcurrent units without any effect on the earth fault relay. Two elements are often considered sufficient 2s any interphase fault must affect at least one of the relays, however, consideration must be given to the possibility of 2-1-1 current distribution i n the system (refer deltalstar transformer protection). It should be noted that on an LV 4 wire distribution system, 4 CT's will be required to ensure stability under all load conditions, the 4th CT being placed in the neutral connection. This fourth CT can be omitted if the earth fault relay setting is above the maximum spill current caused byunbalanced loads, but as the degree of unbalance is not riorii~aiiykiiowii (accilrately) the inclusion of the 4th CT is recommended.

Time Grading The procedure for grading is similar to that for phase fault relays. It is important to appreciate that fuses cannot discriminate between phase faults and earth faults and therefore grading of earth fault relays (which have relatively sensitive settings) with fuses is not possible. When the system contains some neutral earthing impedance, the earth fault level is practically constant over the whole system and grading is carried out at !his fault level. As the fault level is consJant there is no particulai advantage is using IDMT earth fault relays over definite time earth fault relays. Sensitive Earth Fault Relays Where the earth path resistivity is high which may be the case on systems that do not utilise earth conductors, the earth fault current may be limited to such an extent that normal earth fault protection may not be sensitive enough. To overcome these problems a very sensitive relay is requirgd, but the relay must have a very low burden in order that the effective setting is not increased. This very sensitive protection cannot be graded with other conventional systems and it is normal to apply this protection with a definite time delay of up to 10 or 15 secs. This time delay will prevent unwanted operation due to transient unbalance under phase fault conditions. Care must be taken to ensure that the relay setting is above any residual current that may be present under normal load conditions. This may be due to slight d~fferencesin CT characteristics or unbalanced leakage (capacitive) currents in the primary system. In order to ensure that the relay will reset after the transient operation of the current measuring unit, the dolpu ratio should be high, i.e.. approximately 99%.

IN'TERCONNECTED SYSTEMS The foregoing has basically looked at grading procedure as applied to radial feeders. If the system is interconnected and involves parallel paths and rings, the grading can become increasingly more complex. For example, the operation of a particular circuit breaker may not itself result in the isolation of the faulty plant, but may affect the fault current distribution in the other circuits. The affect of this may be to start other relays operating or to change the operating parameters of relays that havealready started. On such interconnected systems the fault level does not tend to vary very much and it may be found impossible to obtain correct discrimination for all faults. The system must be looked at in detail under maximum and minimum fault conditions and the best compromise reached. Very often directional overcurrent relaying can help to overcome the problems slightly.

Page 9

Directional Overcurrent

GiRECTiGNAL OVERCURRENT RELAYS If fault current can flow in both directions through the relay location it is necessary to add directional properties to the overcurrent relays in order to obtain correct discrimination. Directional protection is commonly applied in two areas, namely, parallel feeders(transf0rmers) and ring mains.

RING MAINS

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The more usual application of directional relays is to ring mains. In the case of a ring system, fed at one point only the relays at the generafion end and at the mid-point substation, where the setting of both overcurrent relays are identical, the relays can be made non-directional, provided that in the latter case the relays are located on the same feeder, one at each substation. In this respect it is interesting to note that when the numbers of feeders in the rings is an even number, the two relays with the shme operating time are at the same substation and.will have to be directional whereas when the number of feeders is odd, the two relays.with the same operating time are at different substations and therefore, do not need'to be directional. Also at intermediate substations it will be noted that whenever the times of the two relays at a substation are different, the difference in operating time is never less than the grading interval of 0-4 seconds and consequently it is permissible for the relay with the larger operating time to be non-directional. Grading Ring Mains The usual practice for grading relays in an interconnected system is to open the ring at the supply point and to grade the relays first clockwise and then anti-clockwise. Thus, the relays looking in a clockwise direction around the ring are arranged to trip in the sequence 1 - 2 - 3 - 4 - 5 -3and the relays looking in the anti-clockwise direction are arranged to trip in the sequence 1' - 2' - 3' - 4' - 5' - 6'. The arrows indicate the direction in which the power must flow in order that the directional units will close their contacts and prepare the overcurrent elements for operation. The double headed arrows on each of the two ieeders at the generating station indicate non-directional relays, directional features being unnecessary at these points, because power can flow in one direction only, that is out of the generating station. At all other points s~ngleheaded arrows are shown. These ind~catedirect~onalrelays connected so as to operate with power flow in the direction of the arrow which is in every case from the substat~onbus bars and into the protected line. See Figure 1. This rule is invariable and applies to all forms of directional relays. Selection of the faulty section is by time and fault power direction. Fault power has two phases x and y. It divides between the two paths in the inverse ratio of the impedances an.d passes through all the substations in the ring. Thus, at every substation one set of relays will be inoperative because the power flow is against the arrow and other set operative because the flow is with the arrow. In every case it will be found that the time settings of the relays that are inoperative are shorter than those of the operative relays, except in the case of substation C where the settings happened to coincide. In this way, all relays with short time on sections between the fault one and the generating station are prevented from operation. The others, which are operative are graded downwards towards the fault and the last to be traversed by the fault current, namely that on the faulty feeder section, has the shortest time and operates first. This applies to both paths to the fault. Consequently, the faulty sectioh is the only one to be isolated and supply is maintained to all substations.

Page 1

Grading Ring Mains With More Than One Source

When grading ring systems with more than one infeed (say two sources of supply) the best method of approach is to either : a)

b)

Open the ring at one the supply points by means of a suitable high set instantaneous overcurrent relays and then proceed to grade the ring as in the case of a single infeed. Treat the inter-connector between the two sources of supply as a continuous bus, separate from the ring and protect it by means of a unit system of protection such as pilot wire relays. Then proceed to grade the ring as in the case of a single infeed.

PARALLEL FEEDERS -

If non-directional overcurrent relays are applied to parallel feeders any faults occurring on any one line will inevitably, irrespective of the relay setting chosen, isolate both lines and completely disrupt the supply. To ensure discriminative operation of the relays during line faults, it is usual with this type of system to design and connect relays Rq' and R2' such that they will only operate for faults occurring on the protected line in the direction indicated by the arrows. See Figure 2. With parallel feeders to ensure correct discrimination during line faults, it is important that the correct direct~onalrelay R1' or R2' operates before the non-d~rectionalrelays Rq and R2. For this reason relays R1' and R2' are given lower time settings than relays R1 and R2 and also lower current settings. The usual practice is to set relays Rq' and R2' to 50% of the normal full load of the circuit (ensure that the relays are capable of carrying without damage, twice their setting current continuously), operating with an IOMT characteristic with a TMS 4.0 Care should be taken when using definite time relays. For such applications the directional relays should be set above full load current to prevent them operating due to load current reversal as a result of a phase to phase fault on the other side of the transformer.

ESTABLISING DIRECTION

-

The direction of alternating current can only be determined with respect to a common reference. In relay terms, the reference is commonly referred to as the polarising quantity. The most convenient reference quantity is polarising voltage taken from the power system voltages. The relay compares the power system current against this fixed polarising reference to determine direction of operation.

RELAY CHARACTERISTIC ANGLE (RCA) This is a setting on the relay and is defined as the angle by which the current applied to the relay must be displaced from the voltage applied to the relay to produce maximum sensitivity.

-

Page 2

RELAY CONNECTIONS This is the angle by which the current applied to the relay is displaced from the voltage applied to the relay at unity power factor. The 90" connection (quadrature connection) is now used for all overcurrent relays. n 30" and 60" connections were used in the past, but no longer, as the 90" conneciion gives better performance. The 90" connection is achieved by using IA and VBC. Hence, for an A phase fault the polarising voltage does not collapse. Without a polaring voltage most relays are unable to make a directional decision. Modern numerical relays are able to use prefault data to make a decision, a technique referred to as memory .polarising.

90" Connection - 45" RCA The 'a' phase relay is supplied with la current and Vbc volts displaced 45" in an anticlockwise direction. ln-this case the relay maximum sensitivity is produced when the current lags the system phase to neutral voltage by 45". This connection gives a correct directional tripping zone over the range of current 45" leading to 135" lagging See Figure 3.

TYPICAL RCA SETTINGS A relay designed for quadrature connection and having an RCA of 30" is recommended when the relay is being used for the protection of plain feeders with zero sequence source behind the relaying point. In the case of transformer feeders or feeders which have a zero sequence source in front of the relay, a quadrature connected relay is recommended but it is preferable when protecting this type of feeder that the directional relay is designed to have an RCA 45". An RCA 45" is necessary in transformers and transformer feeders, to ensure correct relay operation for faults beyond the starldelta transformer. 'Three fault conditions may theoretically cause mal-operation of the directional relay. They are phase to phase to ground on a plain feeder; phase to ground fault on -a transformer feTdmwlththezero sequence s o u r c e ~ l n f r o n t o t t h e l a ~ p h W t t o phase fault on a transformer with the relay looking into the delta winding of the transformer.

DIRECTIONAL EARTH FAULT RELAYS These relays are similar in construction to the overcurrent relays but are polarised by residual voltage or current. The polarising voltage is obtained from the secondary of a three phase voltage transformer connected in broken delta. It is essential to ensure that the correct voltage is fed to the relay that the voltage transformer primary neutral is earthed and that it be a three phase, five limb type or consist of three single phase units. Current polarisation is normally obtained by connecting a current transformer in a local jransformer neutral. If voltage polarisation is used a 45" RCA is normally used for solidly earthed systems and 0" for resistance earthed systems.

Page 3

Voltage Polarised Earth Fault Relays Some care is necessary when using voltage polarised relays on solidly earthed systems, as the residual voltage under single phase to earth fault conditions will be equal to the phase to neutral voltage at the fault location or a sol~dearth fault only. Any line impedance between the fault point and the relay, or resistance in the fault itself will tend to reduce the value of the voltage and it can be very small if the line impedance between the fault point and the relaying point is large compared with the source impedance behind the relay. With modern directional relays however, which will operate down to 1OO/ of normal voltage, no trouble should be experienced.

-

Current Polarised Earth Fault Relays As already mentioned, current polarised relays may be polarised by a current transformer connected in the power transformer neutral Only certa~ntypes of power transformers however, are suitable as sources of polarising current, as in some the direction of the current in the neutral can reverse*depending upon the fault position and the ratio of system zero sequence impedances. A staristar power transformer is not suitable for polarising relays even if both star points are earthed. A current transformer in one neutral would not be suitable as the current would reverse depending upon which side of the transformer the fault is on. Paralleling two current transformers, one in each neutral connection, will not be satisfactory as the resultant current would zero. Three winding or two winding power transformers with one winding delta connected are suitable for relay polarisation. Provided the star point is earthed, then a current transformer in t h ~ sneutral can be used to supply the relay. In the case of three winding transformers, if two star connected windings have the star point earthed, then current transformers in each neutral connected in parallel must be used having ratios inversely proport~onalto the power transformers voltage ratio. An alternative to this is to use one current transfomer within the delta winding provided that no load is taken from the delta. If load is taken from the delta winding it is necessary to use a current transformer in each leg of the delta to prevent unbalanced load or fault current producing incorrect polarising current. Dual Polarised Earth Fault Relays As the polarising current for current polarised earth fault relays is taken from a current transformer in a local power transformer neutral, this may be lost if the particular transformer is switched out of service and for this reason voltage polarisation is in general more reliable. However, as pointed out, in solidly earthed systems where the zero sequence source impedance is small the value of the residual voltage can be very low and dual polarised relays, with both current and voltage are used. It should be noted, however, that with modern relays the possibility of voltage polarised relays failing to operate is very remote and that for all practical conditions this possibility can in general be ignored.

Page 4

The operation of earth fault indication relays on systems earthed through a Petersen Coil or totally insulated system is dependent on the capacitive current flowing in the healthy feeders and when a Petersen Coil is used on the current due to the suppression coil flowing in the faulty phase. In the case of overhead lines the majority of earth faults are of a transient nature and it is preferred that these faults shall not lead to automatic isolation of the faulty line. It is desirable, however, that an indication should be given of sustained system faults in order that the system may be supervised continuously and so that the faulty section of the network is indicated. For detection of a system earth fault, a sensitive directional relay or wattmetric relay is used (Petersen Cod Systems) Petersen Coil Earthed System The diagram in Figure 4 shows asystem 0-f radial feeders, with a phase to ground fault on the 'C' phase of one of the feeders. No current will flow in the 'C' phase of the healthy feeders as they will be at earth potential. Capacative current will flow in the healthy phases of all feeders to earth and back to the source via the fault. The vector sum of the currents-in the current coil of the relay on the faulty feeder Is is

1

':I

proportional to :

Where :

The vector diagram of the currents in the sound phases'shows that the total wattage component of the currents in the restraining quadrant, hence the relays on the healthy feeders will not operate. However, the current in the faulty feeder show that the wattage component of the currents'is in the operating quadrant and hence, the relay in the faulty feeder will operate.

1 I

I

I

The current transformers are of a special design, class 0.2, having an exceptionally low phase angle error and because of this cannot be balanced accurately for currents greatly in excess of rated current. The relay is provided with 0" MTA. Insulated System The diagram in Figure 5 shows a system of radial feeders, with a phase to ground fault on the 'C' phase of one of the feeders. The residual current flowing in the current coil of the relay on the faulty feeder, neglecting the effect of magnetising current, is proportional to the 2 lc where lcis the vector sum of the currents in the healthy phases Ica and Icb. Since the system is an insulated one, the fault has the effect of raising the neutral point of the system by a voltage equivalent to the phase voltage and the voltages'of the healthy feeders by A . The relay is provided with a 90" leading MTA.

Page 5

FIGURE I RING MAIN OVERCURRENT PROTECTION

Page 6

. :.

FIGLIRE 2 RING MAIN OVERCURRENT PROTECTION

UNITY P.F.

+ZERO P.F.

- -

ZERO SENSITIWTY LINE

FIGURE 3 90" CONNECTION 45O RCA i

. . I

Page 8

a b c dB

ib db

I 1 I

+La w

+lcb

T

T.-A-----).--

Source

+lca

I

iD 4D

4D

dB

+Icb

I

0

1c

I I

w

T

4

I I

I

dD

I

1c -\ - - ---+ - I- ,

1 I ----)

dB

I

0 4B

T

I

I

I

1ca b

w .

-

T

I I I

I

I

c

.

1 .

- - 1-1c

21, / -+-

Location of CT's

Restrain

Operate

Healthy Feeders

Faulty Feeder FIGLIRE 4

I I I I

7

I

I

I I

a b c

~ o c a t i i nCT'S Faulty Feeder

t

vRE

~VRE.

AVRE

/

kA #

/ /

Restrain

'

.

+

- = -21, RCA +Operate

1

Restrain 4

'VPO FIGURE 5

+ VPO

a

RCA +Operate

ction Notes

Power transformer is one of the most important links in a power system. Its development stems from the early days of electromagnetic induction, when it was discovered that varying magnetic flux in an iron core linking two coils produces an inducted voltage. From the basic discovery has evolved the power transformer we know today using advanced insulation materials and having complex windings on a laminated core using special magnetic steels cold rolled to ensure grain orientation for low loss and high operating density. With transformers of large capacity, a single transformer fault can cause large interruption to power supplies. If faulted transformer is not isolated quickly, this can cause serious damage and also power system stability problems. Protective systems applied to transformers thus play a vital role in the economics and operation of a power system. In common with other electrical plants, choice of suitable protection is governed by economic considerations brought more into prominence by the range of size of transformers which is wider than for most items of electrical plant. Transformers used in distribution and transmission range from a few KVA to several hundred MVA. Fo( transformers of the lower ;stings, only the simplest protection such as fuses can be justified and for large rating transformers; comprehensive protection scheme should be applied.

1

TRANSFORMER FAULT CATEGORIES

I

Transformer faults are generally classified into four categories :

I

I

i) ii) iii) iv)

Winding and terminal faults Core faults Abnormal operating conditions such as overvoltage, overfluxing and overload Sustained or uncleared external faults.

TRANSFORMER CONNECTIONS With tlie development of polyphase systems with more complex transformer winding connections and also possible phase displacement between primary and secondary windings, standardisation was necessary to ensure universal compatibility. (BS171 : 1970) There are a number of possible transformer connections but the more common connections are divided into four main groups : Group 1

0;

Phase displacement

e.g. Yyo Ddo Zdo 180.. Phase displacement e.g. Yd6 Group 2 Dd6 026 Group 3 30" lag Phase displacement e.g. Y d l D Y ~ Yz1 Group 4 30' lead Phase displacement e.g. Y d l l Dyll Yzl 1 High voltage windings are indicated by capital letters and low voitage windings by small letters (reference to high and low is relative). The numbers refer to positions on a clock face and Page 1

indicate the phase displacement of the low voltage phase to neutral vector with respect to the high voltage phase to neutral vector, eg Y d l indicates that the low voltage phase vectors lag the high voltage phase vectors by 30" (-30"phase shift). Individual phases are indicated by the letters A, B and C, again capital letters for the high voltage winding and small letters for the low voltage winding. All windings on the same limb of a core are given the same letter. A further numerical subscript serves to differentiate between each end of the winding. 8

Determination of Transformer Connections

, !

i

!-

This is best illustrated by considering a particular example. The following points should be noted: a)

The line connections are normally made to the end of the winding which carries the subscript 2, ie : A2, 62,C2 and a2, b2, c2.

b)

The line terminal designation (both letter and subscript) are the same as those of the phase windins to w h ~ c hthc line terminal is connected.

Consider the connection Yd1

i)

Draw the primary and secondary phase to neutral vectors showing the required phase displacemed :

Phase rotation

Phase rotation T

4 -

b Secondary

Primary ii) .

Complete the delta winding connection on the secondary side and indicate the respective vector directions :

...

111)

C

A 4 B

\ It is now possible to indicate the winding subscript numbers bearing in mind t-hh if the direction of induced voltage in the high voltage winding at a given instant is Crom A1 to A2 (or vice verse) then the direction of the induced voltage in the low voliage winding at the same instant will also be from a1 to a2. Page 2

I

.

iv)

.

It can now be seen'that the delta connection should be made by connxting a2 to c l , b2 to a1 and c2 to b l :

-

OVERCURRENT PROTECTION

I

(

Fuses Small distribution transformers are commonly protected only by fuses. In many cases no circu~t breaker is provided, making fuse protection the only available means of automatic isolation. Fuses are overcurrent devices, and must have ratings well above the maximum transformer load current in order to carry, without blowing, the short duration overloads that may occur because of such as motor starting. Also the fuse must withstand the magnetising inrush of the transformer. It follows that fuses will do little to protect the transformer, serving only to protect the system by disconnecting a faulty transformer after the fault has reached an advanced stage Overcurrent Relays Overcurrent relays are often the only form of protection applied to small transformers. They are used for backup protection for larger transformers and both instantaneous and time delayed overcurrent can be applied. Inverse time relays on the HV side of a transformer must grade with those on the LV side which in turn must grade with the LV outgoing circuits. Due to this, the HV overcurrent relays could have operating times which might cause operation of relays at other substations. To overco-me this problem, high set instantaneous overcurrent relays with low transient overreach are sometimes used. The settings of these relays should be 120-13O0/0 of the through fault level of the transformer to ensure that the relays are Page 3 .

. ~. ~~

.

stable for through faults. Care must also be taken to ensure that the relays d o not operate under magnetising inrush conditions.

DIFFERENTIAL PROTECTION The function of differential protection is to provide faster and more discriminative phase fault protection than that obtainable from simple overcurrent relays. Overall differential protection may only be justified for larger transformers( Typically >5MVA). CTs on the HV side are balanced against'CTs on the LV side. There are a number of different connections but there are some important points that are applicable to all schemes. Transformer Connection Consider a deltalstar transformer. An external earth fault on the star side will result in zero sequence current flowing in the line but due to the effect of the delta winding there will be no zero sequence current in the line associated with the delta winding. In order to ensure stability of the protection this zero sequence current must be eliminated from the secondary connections on the star side of the transformer, ie the CTs on the star side of the transformer should be connected in delta. With the CTs on the delta side of the transformer connected in star, the 30" phase shift across the transformer is also catered for. Since the majorlty of faults are caused by flashovers at the transformer bushings, it is advantageous to locate the CTs in the adjacent switchgear. Interposing CT (ICT) Where it is not possible to correct for zero sequence current and the phase shift across the transformer by using delta connected line CT's on the star side of the transformer, or were CT ratio mismatch exists between primary and secondary CT's, then interposing CT's are used. Tranditional ICT's were external devices, however modern numerical relays are able to account for ratio error, phase shift and zero sequence current within the relay. This eliminates the use of external ICT's and allows the protection to be set up and installed more easily. General Rules for CT Connections CT connections opposite to main-transformer : ie.

star CTs on delta side delta CTs on star side

If similar primary terminals ie PI or P2 are towards the transformer, then delta and star connection for the CTs should be the same as the transformer (or 180" opposite). It is usual to assume that if current flows from P i flow from S2 -+ SI.

--+

P2 then the secondary current will

Note :If the transformer induced voltage is A1 --+ A2 then the secondary induced voltage will be a1 -+ a2. Therefor?, current flo'w will be A1 --+ A2 and a2 -+ a1

I

Page 4

Tap Changers Any differential scheme can only be balanced at one point and it is usual to choose CT ratios that match at the mid point of the tap range. Note that this might not necessarily be the normal rated voltage. For example, if the tapping range is +1O0h, -20% then the CT ratio should be based on a current corresponding to the -5% tap. The theoretical maximum out of balance in the differential circuit is then +_ 15%. Three Winding Transformers Differential protection of three winding transformers is essentially similar to that of two winding transformers. The same rules regarding CT connections still apply but the CT ratios used shpuld be based on the MVA rating of one of the windings (usually the highest rated winding) and not on the ratings of each individual winding. For example, consider a 13213311'I kV transformer with windings rated for 100/60/40 MVA respectively, then the current transformer ratios at all voltage levels should be based on 100 MVA, ie 44011. 176011 and 528011 respectively (these effective ratios are normally obtained by the use of interposing CTs which means that, for example, all the main CTs associated with the 11 kV system can be made equal to 200011 - rated current). If there is a source associated with only one of the transformer windings, then a relay with only two bias coils can be used.- the CTs associated with the other two windings being connected in parallel. If there is more than one source of supply then it is necessary to use a relay with three bias windings in order to ensure that bias is available under all external fault conditions.

Page 5

Combined Differential and Restricted Earth Fault Protection

:

Although it is preferable to use separate CTs for restricted earth fault protection, it can be combined with differential protection using the same current transformers, together with interposing current transformers. A CT is required in the neutral connection and should be the same ratio as the line current transformers.

,

1

i

I

i I

I

II 'I

DIFFERENTIAL

Page 6

Magnetising Inrush

-

When a transformer is first energised, a transient magnetising currqnt flows, which may reach instantaneous peaks of 8 to 30 times those of full load. The factors controlling the dirration and magnitude of the magnetising inrush are :

I

i) ii) iii) iv) v)

Size of the transformer bank Size of the power system Resistance in the power system from the source to the transformer bank Residual flux level Type of iron used for the core and its saturation level.

There are three conditions which can produce a magnetising inrush effect :

.

i)

First energisation

ii)

Voltage recovery following external fault clearance

iii)

Sympathetic inrush.due to a parallel transformer being energised.

Under normal steaay state cond'itions the flux in the core changes from maximum negative value to maximum positive value duriqg one half of the voltage cycle, ie a change of 2 0 maximum. Since flux cannot instantly be created or destroyed this transformers are normally designed and run at values of flux approaching the saturation value, an increase of flux to double this value corresponds to relationship must always be true. Thus, if the transformer is energised at a voltage zero when the flux would normally be at its maximum negative value, the flux would rise to twice its normal value over the first half cycle of voltage. This initial rise could be further increased if there was any residual flux in the core at the moment the transformer was energised. Since extreme saturation which requires an extremely high value of magnetising current. As the flux enters the highly saturated portion of the magnetising characteristic, the inductance falls and the current rises rapidly. Magnetising impedance is of the order of 2000% but under heavily saturated conditions this can reduce to around 40% ie an increase in magnetising current of 50 times normal, This figure can represent 5 or 6 times normal full load current. Analysis of a typical magnitude inrush current wave shows (fundamental = 100%) :

Component

-DC

2nd H

3rd H

4th H

5th H

6th H

7th H

55%

63%

26.8%

5.1%

4.1%

3.7%

2.4%

The offset in the wave is only restored to normal by the circuit losses. The time constant of the transient can be quite long, typ~cally0.1 second for a 100 KVA transformer and up to 1 second for larger units. Initial rate of decay is high due to the low value of air core reactance. When below saturation level rate of decay is much slower. The magnitude of the inrush current is limited by the air core inductance of the windings under extreme saturation conditions. A transformer with concentric windings will draw a higher magnetising current when energised from the LV side, since this winding is usually on the inside and has a lower air core inductance. Sandwich windings have approximately equal magnitude currents for both LV and HV. ' Resistance in the source will reduce the magnitude current and increase the'iate of decay.

Page 7 I

p

. ..

Effect on Differential Relays Since magnetising inrush occurs on only one side of the transformer, the effect is similar to a fault condition as far as differential protection is concerned. The following methods are used to stabilise the relay during magnetising inrush period.

.:

.

Time delayed - acceptable for small transformers or where high speed operation is not so important. (Note : necessary time delay when associated with parallel transformers could be excessive). -

Harmonic restraint - usual to use 2nd H restraint since magnitude inrush current contains pronounced 2nd harmonics. Note : 3rd H restraint should not be used for two reasons : a)

Due to-delta connections in the main transformer and in the CT circuits (which provide a closed path for third harmonic currents), no third harmonic current would reach the relay.

b)

CT saturation under internal fault conditions'also produces harmonics of which the 3rd is the most predominant. Second harmonics are also produced under these conditions (combination of dc offset and fundamental) so excessive saturation of CTs should be avoided.

The problem of any restraining tendency due to 2nd H currents produced by CTs saturating under heavy internal fault conditions is usually overcome by using high set instantaneous un~ts set at 8-10 x rated current. While the second harmonic produces a useful restraint during external faults, it can produce unwanted restraint for Internal faults, due to dc saturation of CTs. Extremely large CTs are required such that they do not saturate and affect the operating times of the differential relay. Gap Detection - If the various current waveforms that occur during magnetising inrush are analysed, it can be found that the magnetising currents have a significant period in each cycle where the current is substantially zero. Fault current, on the other hand, passes through zero very quickly. Detection of this zero is considered a suitable criteria.

Thus, a transformer differential relay can be made to restrain if zero is detected In a cycle for more than a certain period (typically 114f seconds). With the above principle of detection of magnetising inrush, fast operation of the relay can be achieved for internal faults and economically designed CTs can be used, without affecting the speed of operation.

Page 8

;?

:j;

.

.

-$ ;? . .

I

VARIATION OF EARTHFAULT CURRENTS ON TRANSFORMER WINDINGS An earthfault is the most common type of fault that occurs in a transformer.

1

For an earthfault current to flow, the following conditions must be satisfied :

1 I

a path exists for the current to flow into and out of the windings, ie a zero sequence path

the ampere turns balance is maintained between the windings.

-

I

The magnitude of earthfault current is dependent on the method of earthing solid or resistance and the transformer connection.

Star Winding

- Resistance Earthed

An eadhfault on such a winding will give rise to a current which is dependent on the value of earthing impedance and is also proportional to the distance of the fault from the neutral point, since the fault voltage will be directly proportional to this distance. The ratio of transformation between the primary winding and the short circuited turns also varies with the position of the fault, so that the current which flows through the transformer terminals will be proportional to square of the fraction of the winding which is short circuited.

1

If the earthing resistor is rated to pass full load current, then

1

Assuming V, = V,. then T, = 43 TI

Page 9 -

For a fault at x p.u. distance from the neutrgl,

Effective turns ratio = T2 I x TI

Primary C.T. ratio is based on lF.L. for differential protection.

:.

C.T. secondary current (on prin~aryside of transformer)

xL

= --F \I

I f differential setting = 20%

For relay operation

A

Y'

> 20°/c

3

thus x > 59% i.e. 59% of winding is unprotected. Differential relay setting

Oh

of winding protected

If as multiple

of ~ F . L .

Pase 10

3

Star Winding

-

Solidly Earthed

In this case, the fault current is limited only by the leakage reactance of the winding, which varies in a complex manner with the position of the fault. For the majority of the winding the fault current is approximately 3 x Iflc, reaching a maximum of 5 x Iflc.

1

From a study of the various current distributions shown for earth faults, ~tis evident that overcurrent relays do not provide aaequate earth fault protection. If the system is solidly earthed, some differential relays adequately cover the majority of faults, but in general separate earth fault protection is necessary.

I

EARTH FAULT PROTECTION

I

Balanced earth fault for a delta (or unearthed star) winding can be provlded by connecting three line CTs in parallel (residual connection). The relay will only operate for internal earth faults since the transformer itself cannot supply zero sequence current to the system. The transformer must obviously be connected to an earth source.

It is usual to provide instantaneous earth faultprotection to transformers since it is relatively easy to restrict the operation of the protection to transformer faults only, ie the protection remains-stable for external faults. This protection is called balanced Gr restricted earth fault and the high impedance principle is utilised. However, modern numerical relays provide do provide both high and low impedance restricted earthfault protection.

Source (Earthed)

w

Balanced Earth Fault

For an earthed star winding, the residual connection of line CTs are further connected in parallel with a CT located in the transformer neutral. Under external earth fault conditions the current in the line CTs is balanced by the current in the neutral CT. Under internal fault conditions. current only flows in the neutral CT and since there is no balancing current from the line CTs, the relay will operate. On four wire systems in order to negate the effect of the neutral return current a further CT placed in the neutral and wired in parallel with the existing CT's. On a four wire system with the transformer earthed at the neutral point 5 CT's are required. However, if the transformer is earthed at the LV switch board only 4 CT's are required. If no neutral CT is used then therelay will have to be set above the maximum expected unbalance current in the neutral return.

I

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Page 11

A relay, insensitive to the dc component of fault current is normally used for this type of .. . protection. If a "current operated" relay is used, an external stabilising resistor is placed in series with the relay to ensure protection stability under through fault conditions. The protection setting voltage is calculated by conventional methods. To reduce the setting voltage it is often useful to run three cores from the neutral CT in order that the relay is connected across equ~potentialpoints.

.. .. .

..:

Typical Settings for REF Protection (From ESI 48-3 1977) 10-60% of winding rated cur-rent

Solidly earthed Resistance earthed

-

10-25% minimum earth fault current for fault at transformer terminals

Unrestricted Earthfault Protection Unrestricted earth fault or backup earth fault protection can be provided by utilising a single CT mounted on an available earth connection eg transformer neutral, or (on an earthed systern) by using a residual connection of three line CTs. In this case, the relay should be of the inverse or definite time type in order to ensure correct discrimination.

.; ..

:.

On resistance earthed system, unrestricted earth fault protection is referred to as standby earth ,..; fault protection. An inverse time relay is used which matches the thermal characteristic of the .:: earthing resistor. Earthing resistors normally have a 30 second rating and are designed to limit : the earth fault current to transformer full load current. 4

: :,

FAULT CURRENT DISTRIBUTION IN TRANSFORMER WINDINGS Under fault conditions, currents are distributed in different ways according to winding connections. Understanding of the various fault current distribution is essential for the design of differential protection. performance of directional relays and settings of overcurrent relays. Fault current distribution on a delta-star transformer, star-star transformer with unloaded tertiary and star-delta transformer with earthing transformer for phase and earthfaults are shown in the diagrams below :

b2 Source

_

_

P

__t

PH-E Fault

I3 Source

-

-

B

I

-

c2

PH-PH Fault

Fault Current Distribut~onon a Star - Star Transformer with Unloaded Tertiary

BUCHHOLZ PROTECTION All types o i fault wlth~na transformer w~llproduce heat which will cause decomposition of the transformer oil The resulting gases that are formed rise to the top of the tank and then to the conservator. A buchholz relay connected between the tank and conservator collects the gas and glves an alarm when a certain volume of gas has been collected. A severe fault causes so much gas to be produced that pressure is built up in the tank and causes a surge of oil. The buchholz relay will also detect these oil surges and under these conditions is arranged to trip the transformer circu~tbreakers. The maln advantage of the buchholz re4ay is that it will detect incipient faults which would not oiherw~sebe detected by conventional protection arrangements. The relay is often the only way of detect~nginterturn faults which cause a large current to flow in the shorted turns but due to the large ratlo between the shorted turns and the rest of the winding, the change in terminal currents IS very small

PARALLEL TRANSFORMERS Parallel transformers are typically protected by directional overcurrent and earthfault protection on the LV side set to look back into the transformers. Where an LV bussection exists the directional relays can be replaced by non-directional relays, with the addition of a non-directional overcurrent and earthfault relay at the bus-section.

If a transformer is connected in parallel with another transformer which is already energised, magnetising inrush will occur in both transformers. The dc component of the inrush associated with the switched transformer creates a voltage drop across the line resistance between the source and the transformer. This voltage causes an inrush in the opposite direction in the transformer that was already connected. After a time the two currents become substantially equal and since they flow in opposite directions in the transmission line they cancel and produe no more voltage drop in the line resistance. The two currents then become a single circulating current flowing around the loop circuit made up of the two transformers in series -the rate of decay being determined by the R/L ratio of the transformer.

Page 14

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OVERLOAD PROTECTION Overloads can be sustained for long periods with the limiting factor being the allowable temperature rise in the windings and the cooling medium. Excessive overloading will result in deterioration of insulation and subsequent failure.

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p s far as protection IS concerned, non-harmonic restraint should not be used due to the long time delay required. A harmonic restrained relay should be used for each transformer since if a common relay were used the 2nd harmonic resGaint could be lost due to cancellation as described above.

Overloads can be split into two categories : Overloads which do not reduce the normal expectation of life of the transformers. Overloads in this category are possible because the thermal time constant of the transformer means that there is a con,siderable time lag before the maximum temperature correspond to a particular load is reached. Quite high overloads can therefore be carried for short period.

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Overloads in which an allowance is made for a rapid use of life than normal. The length of life of insulation is not easily determined but it is generally agreed that the rate of using life is doubled for every 6°C temperature increase over the range 80-140°C (below 80°C the use of life can be considered negltgible).

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A hot spot temperature of 98°C gives what may be considered the normal rate of using life, ie a normal life of some tens of years. This temperature corresponds to a hot spot temperature.rise of 78°C above an ambient temperature of 20°C. The graph below indicates the relative'rate of using life against hot spot temperature.

Relative rate of

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Hot Spot T e m p

Protection f o r Overloads Since overloads cause heating of the transformer above the normal recommended temperatures, protection against overloads is normally based on winding temperature

Page 15

Transformer Setting Tutorials

:

Advanced Industrial Power System Protection

Transformer setting Criteria & Tutorials Page 1 of 33

INTRODUCTION

Power Transformer- is one of the most important links in a power system. W~thTransformers of larger capacity , a single transformer fault can cause large interruption to power supplies. If faulted transformer is not isolated quickly, this can cause serious damage and also power system stability problems. Protective system applied to transformers thus play a vital role in the economics and operation of a power system. In common with other electrical plants, choice of suitable protection is governed by economic considerations brought more into prominence Ly the range of size of transformers which is wider than for most items of eiectrical plant. For transformers of the lower ratings , only the simplest protection such as fuses can be justified and for large rating transformers , comprehensive protection scheme should be applied.

Transformer faults are generally classified into four categories: 1 ) Windlng terminal faults' 2) Core faults 3 ) Abnormal operating conditions , such as overvoltage, Overfluxing and overload 4 ) Sustained or uncleared external faults

TRANSFORMER CONNECTIONS With the development of poly phase systems with more complex transformer connections and also poss~ble phase displacement between primary and secondary windings, standardisation was necessary to ensure universal compatability( BS 171: 1970) There are a number of possible transformer connections but the more common connections are divided into four groups. Group1

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Transformer setting Criteria & Tutorials Page 2 of 33 .-

Group2

180degree phase displacement

Group3

30degree Lagphase displacement

E.g Yy6 Dd6 Dz6 E.g Ydl DY1 Yzl

Group4

30degree Leadphase dispiacement E.g Yd 1 1 Dyl 1 Yzl 1

High voltage windings are indicated by capital letters and low voltage windings by snmll letters (reference to high and low is relative). The numbers refers to positions on a clock face and indicate the phase displacement of the low voltage phase to neutral vecior , e.9,Yd 1 indicates that the low voltage phase vectors lag the high voltags phase vectors by 30 degree (-30 degree phase shift] Individual phases are ind~catedby the letters A,B &C , again capital letters for the low voltage winding. All windings on the same limb of a core are given the same letter. A further numerical subscript serves to differentiate between each end of the winding.

PROTECTION APPLIED TO TRANSFORMERS Over current and earth fault protection(Unrestricted)

Plain overcurrent and earth fault protection utilising IDMTL relays are used primarily to protect the transformer against the effects of exiernal short circuits and excess overloads. The current settings of the protection must be above the permitted sustained over load allowance and below the minimum short circuit current. The ideal characteristic i s the extremely inverse (CDG14)as it is closely approximates to the thermal curve of the transformer. The protection is located on the supply side of the transformer and is arranged to trip both the H V and LV circuit breakers. In many cases the requirements for protecting the transformer and maintaining discrimination with similar relays in the remainder of the power syslern are not corilpatibile. In these circumstances , negative sequence filter protecrion or under voltage blocking may be used to obtain the desired ser?sii~vity.. 1 f

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1 . High set overcurrent cut-Off: On small transformers where the main protection is provided with overcurrent devices and where the transformer i s fed from one end only, a high set instantaneous relay i s utilised to provide protection against terminal and internal winding faults. The ,relay is set to be above the short circuit level on the secondary(load ) -side of the transformer and below: that for a terminal fault on the primary (supply)sideof the transformer. On choosing the type and setting of the high set relay, it i s important to consider the magnetising inrush currents under normal switching , offset fault currents and starting currents of motors.The first two problems can be overcome by using a relay sensitive only to fundamental frequency currents, while the third is overcome by setting the relay above the max. starting current level.

2. Stand-by earth fault protection Where transformers are earthed via an earthing resistance which is short time rated , stundby earth fault protection is applied to protect the resistor from damage when an earth fault persists for a time longer than the rating of the resistors. The relay is energised from a CT in the neutral connection and its time of operation is made to match the thermal rating of the resistor. It is arranged to completely isolate . the transformer. Some times a two stage relay is employed, each stage set to operate at a different time. The first staqe arranged to trip the LV breaker and if still the fault is persisting, Ihe second stage relay trips the HV side breaker thus isolating the transiormer completely.

DIFFERENTIAL PROTECTION

The funciion of differential protection is to provide faster and more discriminative phase fault protection than that obtainable from simple over current relays.CTs on the primary and the secondpry sides

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1. Line current transformer primary ratings

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The rated currents of the primary and the secondary sides of a two winding transformer will depend on the MVA rating of thetransformer and will be in inverse ratio to the corresponding voltages. For three winding transformers the rated current will depend on the MVA rating of the relevar-rt winding. Line current transformers should therefore have primary ratings equal to or above the rated currents of the transiormer windings to which they are applied. -

2. Current transformer connections

The CT connections should be arranged , where necessary to compensate for phase difference between line currents on each side of the power transformer. If the transformer is connected in delta/star as shown in figure, balanced three phase through current suffers a phase angle of 30 degree which must be corrected in the CT secondary leads by appropriate connection of the CT secondary wind~ngs. Further more , zero sequence current flowing on the star side of the power transformer .will not produce current outside the delta on the other side. The zerosequence therefore be eliminated from the star side by connecting the CTs in delta, from which i t follows that the CTs on the delta side of the transformers must be connected in star, in order to give 30 degree phase shift. This is a general rule ; if the #

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Figure 1

When Cis are connected I n delta, their secondary rating must be 1 / 43 times the secondary rating of star connected reduced to Cis , inorder that the currents outside the-delta may balance with the secondary currents of the star connected CTs. When line CT ratios proiide adequate matching between currents supplied to the differential relay under through load and through fault conditions , the necessry phase shift can be obtained by suitable connection of the' line CTs . Figure 1 above shows the required connections for various power transformer winding arrangemenis. When delta connected CTs are required it is a common practice to use star conr;ecled line CTs and to obtain fhe delta connection by means of stal-/delta interposing CTs.

3. Bias to cover Tap-Changing facility and CT mismatch

If the transfor-n~er hcs a tapping range enabling its ratio to be varied , this must be allowed for in the differential system. This is because the CTs selecled to balance, for the mean ratio of the power transformer, , a variation in ratio from the mean will create an unbalance proportional to the ratio change. At maximum through fault current , the spill oputput produced by the small percentage unbalance may be substantial. Differential protection should be provided with a proportional bias of at-\ amount which exceeds in effect the maximum ratio deviation. This stabilises ihe protection under through fault conditions while still permitting the system to have good system sensitivity. The bias characteristic for a typical differential protection is shown in figure2, iron-\ which it can be seen that the cursent required to operate the relay increases as the through fault increases.

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When applying a differential relay, care should be taken that its characteristic will prevzr-it operation due to the combination of tap change variation and CT mismatch . To mininiise the effect of tap change variations , current inpuis lo the differeniial relay are usually matched at the mid poini of the tap range..

Figure 3 below shows percentage biased differential protection for a two winding transformer. The two bias windings per phase are conimonly provided on the same electromagnet or auxiliary 1r-a~isfornier core. .

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Advanced Industrial Power System Protection -

The Merz-price principle remains valid for a system having more than two connections, so a transformer with three or more windings can still be protected by the application of above principles. When the power transforn~erhas only one of i t s three windings connected to a source of supply, with the other two windings feeding loads at differ-er~tvoltages, a relay of the same design. as that used for two winding transformer can be employed.

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The separate load cv!rents are summated in the CT secondar;/ circuits, and will balar~ce\with the infeed current on the supply side.

When more tho!] one winding is connected to a source , the disiributiol~of CLII rer~tcz11,1ot readily be predicted and there is u danger in the s c h e r ~ ~sflown e (a) in Ihe figure 4 of current circulaling between the two paralleled sets of CTs with out producing any bias. It i s therefore impor-tani i:lat bias be obtained seperately from the current flowing in each set of line connections. In this case a ~eloy used with separate bios \vindings , arranged so that their mechanical or' electrical effects a l ~ ~ c add y s numerically , that is not vectoria'ily . lo give the total bias eiiezr. This is shown as (b)in the figure 4.

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These considerations do not apply when the third winding consists of a delta connected tertiary with no connections brought out. Such an arrangement may be regarded GS t\.w \vvir,dlr,gtrafisformer --for protection purposes and may be protected as (c)in the figure 4. -

3. Inter posing CTs to compensate for mismatch of Line CTs

Besides their use for phase ccjmpensation, interposing CTs may be used to match up currents supplied to the differential protection from the line CTs for each winding. The amount of CT mism.atch which a relay can tolerate with out maloperation under through fault conditions will depend on i t s bias characteristic and the range over which the tap changer can operate. If the combined mismatch due to CTs and tap changer is above the accepted level , then interposing CTs may be used to achieve current matching at the mid point of the tap changer range.


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Transformer setting Criteria & Tutorials Page 1 1 of 33


For the protection of two winding transformers interposing CTs should ideaiiy t-1-~aichihe---relaycurrents under through load conditions An corresponding to the maximum MVA rating of the tran~fo~mer. example of this for an 1 1 KV/132KV 30MVA, DELTA /STAR transformer is shown in the figure 5.

First the primary ratings of 1600A and200A chosen for the main CTs should not be less than the max. full load currents in each winding , which are ,

30 x 100 = 1575 A For 1 1 KV winding 3 3 i~i x 103 30 x 10. = 164 ,A For 132KV winding \/3x 132 x 103 r the 1 1 KV winding this is also the nominal full load current , but for 1172 132KV winding , with -5% tap , the latter is: 30 x 10" 43 x 0.95 x 132 x 103

= 138A

For 1 1 KV winding

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Figure 5 The pro!eciiori of three winding transfor-nier-sis complicated by the fact that line CTs for each winding ar-e riormally based on different MVA levels and will 1701 ttienlselves achieve balance under ttirough current ronditior~s.To achieve correct balarice , it is necessary to use inlerposir~gCTs wllicti hlill provide the relay with raied currerli when the rating of the highest rated winding is applied to all windings.

An exaniple for a 500KV/138KV/13.45KV, 120MVA/90MVA/30MVA, star/slar/delta transfornler is shown in the figure 6. Load cur rent a i 599

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Line CT ralio at 500KV = 20015 A I-ine CT ratio at 138KV = 40015 A . Line CT ratio at 13.45KV = 150015 A Current at 138 KV corresponding to 120 MVA = 120 x 1 O6 3 x 138x lo3

Current at 13.45 KV corresponding to 120 MVA = 120 x 1 O6 \I3 x 13.45 x lo"

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Transformer setting Criteria &


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SOMVA 1 W V

RELAY FATED CURKEICT Figure 6

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-. lnele iore ratio of required starldelta interposing CTs = 3.461 5 A OR 3.461 2.89 A

\'3 Secondary current from 138 KV line CTs corresponding io 120 M V A

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There fore ratio of required starldelta interposing CTs

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Secondary current from 13.45 KV line CTs corresponding to 120 MVA = 5151 x 5 = 17.17 A 1 500 Therefore ratio of required star/star interposing CTs = 17.1715 A

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Under full load conditions of 30MVA, for the 13.45 KV delta winding , the current appearing in the primary of the 17.17/5 A inter posing CT will only be 4.29 A , the corresponding secondary current being 1.25 A . However the ratings of the primary and the secondary windings should ideally be 17.1 7 A and 5 A respectively to minimise winding resistances.

STABILIZATION OF DIFFERENTIAL PROTECTION DURING MAGNETlSlNG INRUSH Tl~en~agnetisinginrush phenomenon produces current input to the

energised winding which has no equivalent on the other sides of the transformer. The whole of the inrush current appears therefore as unbalance and is no1 distingushable from internal fault current. The normal bias is not , iherefore effective and increase of protection setting to a value which would avoid the operation would make the protection of little value. Harmonic Restraint.

The inrush current, clthough y!~.nerallyresembling an inzone fault current, differs greaily when the waveforms are compared. The distinctive difference in the4 woveforms can be used to distinguish


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between the condition;. The inrush contains all orders of harmonics, but these are not all equally suitable for providing bias. The study of this svbject is complex, as the wave form depends on the degree of saturation and on the grade of iron in the core.

a) D.C Offset component (Zero harmonic) A uni-directional component will usually be present in the inrush current of the single phase transformer and in the principal inrush currents of a three phase unit. However if at the instant of switching the residual flux for any phase is equal to the flux which would exist in the steady staie at that point on the voltage wave , then no transient disturbance should take place on that phase.

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Large inrush c ~ r ~ - e nwill i s flow in the other two phases , corresponding to high peak lux values established in these phase cores. The high flux circulates through the yokes , the saturation of which affects the iir-s: phase , L-:iiich. would have had no inrush effect, causing c substantial transient current to flow in this phase as well. This latter current , however will not be off set from the zero axis , althougt-1the current waveform will be distorted.. If the uni-directional current component were used to stabilise a

differential sysiem, some sort of cross phase biasing would be of this effect. required becc~lse

b) Second Harmonic component This connpone!3t is present in all inrush wave forms . It is typical of wave forms in which successive half period portions do not repeat with reversal oi polarity but-in which the mirror image symmetry can be found abo:lt certain ordinates. The portion of second harmonics varies some what with the degrce of saturation of core , but is always present as long as the unidireciior~ai~ormponentof flux exists. It has been shown to have a minimum value of about 20% of the amount by which the inrush current exceecjs the steady state magnetising current.

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Normal fault current do not contain second or other even harmonics, nor do distorted currents flowing in saturated iron cored coils under steady state conditions. -

The output current of a current transformer which is energized into t steady state saturation will also contain odd harmonics but i ~ oeven harmonics. However, should the current transformer be saturated by the transient component of the fault current, the resulting saturation i s not symmetrical and even harmonics are introduced into the output current. This can have the advantage of improving the through fault stability performance of a differential relay, but it also has the adverse effect of increasing the operatioh time for internal faults. The second harmonic is therefore an attractive basis for a stabilizing bias against inrush effects, but care must be taken to ensure that the current transformers are sufficiently large so that the harmonics produced by transient saturation do not delay normal operation of the relay. .

-

The differential current is passed through a filter which extracts the second harmonic; this component is then applied to produce a restraining quantity sufficient to overcome theoperating tendency due to the whole of the inrush current which flows in the operating circuit. By this means a sensitive and high speed system can be obtained. With the type DTH relay, a static design, a setting of 15% is obtained with an operating time of 45 milliseconds for all fault currents of twice or more times the current rating. The relay will restrain when the second harmonic component exceeds 20% of the current. Third harmonic The third harmonic is also present in the inrush current in roughly comparable proportion to the second harmonic. The separate phase inrush currents are still related in phase to the primary applied electromotive forces and the harmonics have a similar time spacing, which brings the third harmonic waves in the three windings into phase. If the windings are connected in delta, the line currents are each the difference of two phase currents. As the inrush components vary during the progress of the transient condition it is possible for this qifference to pass,through zero, so that the third

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Transformer setting Criteria & . Tutorials Page 18 of 33

harmonic component in the line current vanishes; this component, therefore, be regarded as a reliable source of bias. To this must be added the further consideration that a sustained third harmonic component is quite likely to be produced by CT saturation under heavy in-zone fault .conditions. All this means that the third harmonic is not a desirable means of stabilizing a protective system against inrush effects.

d. Higher harmonics , All other harmonics are theoretically present in inrush current but the relative magnitude diminishes rapidly as the order of harmonic increases; there may be 5% of fourth harmonic in a given inrush 'current. This component would be similar in response to the second harmonic but the small magnitude hardly justifies the provision of an extra filter circuit. ,

A still smaller proportion of fifth harmonic will be present. This component is not subject to cancellation as is the third harmonic, and can be present in the output of a CT in an advanced state of saturation, therefore offering no benefit. Still hlgher harmonics are of magnitude too small to be worth consideration. The percentage of fifth harmonic in the transformer magnetizing current increases significantly when the transformer is subjected to a temporary overvoltage condition. Some manufacturers apply a measure of fifth harmonic bias to the relay to restrain operation for this condition. Typically such relays are restrained if the magnetizing current contains 30% fifth harmonic.

RESTRICTED EARTH FAULT PROTECTION

A simple overcurrent and earth fault system will not give good

protection cover for a star-connected primary winding, part~cularlyil the neutral is eaithed through an impedance. The degree of protection is very much improved by the application of a ur-lil differential earth fault system or restricted earth fault protection, as shown in Figure 7. The residual current of three line current


y


Transformer setting Criteria & Tutorials Page 19 cf 33

transformers is balanced against the output of a current transformer in the neutral conductor. The relay is of the high impedance type.

I

The system is operalive for faults within the region between current transformers, t h a t Is, fs: fai;lts on the star winding in question. The system will remain stable for all faults outside this zone

HIGH lMPEDANCE RELAY

Restric ted earth fault protection for a star winding. Figure 7 The gain in protection performance comes not only from using an instantaneous relay with a low setting, but also because the whole fault current i s measured, not merely the transformed component in the HV primary winding. Hence, although the prospective current level decreases as fault positions progressively nearer the neutral end of the winding are considered, the square law which controls the primary line current is notapplicable, and with a low effective setting, a good percentage of the winding can be covered. Restricted earth fault protection is often applied even when the neutral is solidly earthed. Since fault current then remains at a high value even to the last turn of the winding , virtually complete cover




P a g e 1: for earth faults if obtained, which is a gain compared with the performance of systems which do not measure the neutral conductor current.

..

Earth fault protection applied to a delta-connected or unearthed star winding in inherently restricted, since no zero sequence component can be transmitted through the transformer to the secondary system. A high impedance relay can therefore be used, giving fast operation and phase fault stability.

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Both windings of a transformer can be protected separately with restricted earth fault protection, thereby p~oviding high speed protection against earth faults for the whole transformer with relatively simple equipment.

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This protection is based on high impedance differential principle, offering stability for any type of fault occuring outside the protected zone and satisfactdry operation for faults with in the zone. A high impedance relay is defined as a relay or a relay circuit whose voltage setting is not less tnan the calculated rnax. voltage which. can appear across its terminal under the assigned-max.through fault current condition.

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It can be seen frorn the figure that during an external fault current should circulate between the current transformer secondaries. The only current that can flow through the relay circuit i s due to any difference in CT output for the same primary current. Magnetic saturation will reduce the output of a CT and the most extreme case of stability will be if one CT is completely saturated and the other unaffected. At one end of the CT can be considered fully saturated with i t s magnetising impedance , while the CT at the other end being unaffected , delivers its full current output which which will then divide between the relay and the saturated CT. This division will be in the inverse ratio of R relay circuit and Rct +2RL and obviously if R relay circuit is high compared with Rct +2RL, the relay will be prevented from undesirable operation.

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To achieve the stability for external faults, the.stability voltage for the protection Vs must be determined by the formula, Vs = If (Rct +2RL ) Where Rct = CT secondary winding resistance RL= max. lead resistance from the CT to the common point


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Advanced Industrial Power System Protection . --

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Transformer setting criteria.& Tutorials 21 of 33 Page

To ensure satisfactory operation of the relay under internal fault conditions the CT Knee point voltage should not be less than twice the relay setting voltage. i.e

The setting of the -stabilising resistor must be calculated in the following manner, where the setting is a function of the relay ohmic impedance at setting Rr , the required stability voltage setting Vs and the relay current setting Ir.

1

Rst =

-

lr

Rr

-

-

The ohrriic impedance can be calculated using the relay VA burden at current setting and the current setting Ir,

-1

USE OF MFTROSL OR NON LINEAR RESISTORS. When the max. through fault current is limited by the protected circuit impedance: such as in the case of power transformer REF protection , it i s generally found unnecessary to use non -linear voltage limiting resistors or Metrosils. How ever when the max. through fault current is high , it is always advisable to use a non linear resistor across the relay circuit. Metrsils are used to limit the peak voltage developed by the CTs under internal fault conditions, to a value below the insulation level of the CT s, relay and the connecting leads, wh~chare normally withstand 3000V peak.

The following formulae should be used to estimate the peak transient voltage that could be produced for an internal fault. The peak voltage produced during an internal fault will be a function of the CT Knee point voltage and the prospective voltage that would be produced for an internal fault if CT saturation did not occur. This prospective voltage will be a function of max. internal fault secondary current , the CT ratio , the CT secondary winding resistance, the CT lead resistance to the common point , the relay lead resistance, the stabilising resistor value and the relay burden at relay operating current.

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Page 22 of 33 -

Vp= 2 d 2 Vk (Vf - Vk) Vf = If (Rct +2rl+Rst + Rr )

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Where Vp= Peak voltage developed by the CT under internal fault conditions Vk = CT knee point voltage Vf = max. voltage that would be produced if CT saturation did not occur Max. internal fault sec. Current Rct = CT secondary winding resistance RL = max. lead burden from CT to relay Rst = stabilising resistor Rr = relay ohmic impedance .at setting

When the value given by t h e formula is greater than 3000 V peak, non-linear resistors (metrosils) should be applied. These non-linear resistor s (metrosils)are effectively connected across the relay circuit, or phase to neutral of the ac bus wires, and serve the purpose of shunting the secondary current output of the current transformer from the relay ~norderto prevent very high secondary voltages. These non-hear resistors (metrosils) are externally mounted and take ar of 152 mm diameter and approximately 10 tne form of a n n ~ ~ l discs, mm thickness. The operating characteristics follow the expression:

v=

l-10 2 5

Where V= Instantaneous voltage applied to the non-linear res~stor(metrosils) C= Constant of the non-linear resistor (metrosil) I = lnstantaneous current through the non-linear resistoi (metrosil) For satisfactory application of a metrosil, its characteristic should be sucli that i t requires the following requirement. At the relay voltage setting , the non linear resistor, current should be

as low as possible but no greater than approximately 30mA r.m.s for 1 A CT and approx. 100mA for 5A CTs.


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Total impedance = 14 p.u -.-,

inere foi-e ! I = 1/:4 = Z.C714 p.u

Base current = 80 x 10 6

43x415 = 1 1 1 296 Amps There fore fault current = If = 3x 0.071 4 ~ 1 1 1 2 9 6 = 23840 dmps ( Primary) = 14.9 Amps (Secondary) Setting voltage Vs = If ( R c t + 2 R L ) Assuming Earth CT saturates, Rct = 4.8 ohms 2RL = 2x 100 x 7 . 4 1 ~ 10-3 = 1.482 ohms

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Therefore setting voltage = Vs = 14.9 x ( 4.4+ 1.482) = 93.6 V

Stabilising Resistor

Rst = Vs /IS - VA/ls Where VA is the burden of the relay Is = relay setting current -

Adopt the relay setting as lo%, Rst = 93.610.1 - 1 / (0.112

= 836 ohms EFFECTIVE SElTlNG OF THE RELAY

Effective setting = Ip = CT ratio x (Is + nle) Where n= the no. of CT in parellel le = magnefisingcurrent of each transformer



Advanced Industrial Power System i

I

Protection

Tutorials Page 25 of 33

From the CT characteristics -& the Table i i n e side CTs:

Flux density at 93.6V, = 93.6'1158 = 0.592Tesla Magnetising force at 0.592T = 0.015 AT/mm Therefore magnetising current = 0.015 x 0.341 = 0.0051Amps

Line side CT Earth CT

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1 58 236

1 0.341

1 0.273

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OALSTOM Limited, Energy Automalion & Information


Transformer selting Criteria & Tutorials Page 27 of 33

Flux density at 93.6 V = 93.6 / 236 = 0.396 Tesla

Therefore mag current = 0.012 x 0.275 = 0.0033 Amps

Thus effective setting = 1600 x [0.1 + (3x 0.0051 + 0.0033) ] = 190 Amps

Transformer full load current = 1391 Amps

Peak Voltage developed across the relay circuit = Vp= 2

4 2 Vk

(Vf

-

Vf= 14.9xVs/\s= 14.9x936= 13946volts For earth CT froni the graph, Vk = 1.4~236= 330 V

Therefore Vp = 2

1 1

2 x330 ( 13946 - 330)

Since this value is more than 3 KV

,

Metrosil voltage limiter will be

OVERFLUXING PROTEC'TION

Power frequency overvoltage causes both an increase in stress on the insulation and a proportionate increase in the working flux. The latter

effect

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Advanced industriai Power System Protection


disproportionately great increase in magnetizing current. In addition, flux is directed from-the laminated core structure into steel structural parts. In particular, under conditions of over-excitation of the core, the core bolts, which normally carry little flux, may be subjected to a large component of flux diverted from the highly saturated and constricted region of core alongside. Ui~der such conditions, the bolts may be rapidly heated to a temperature which destroys their own insulation and will damage the coil insulation if the condition cantinues. Reduction of frequency has an effect with regard to flux density, similar to that of overvoltage. It follows that a rransformer can operate with some degree of overvottage with a corresponding increase In frequency, but with a high voltage input at a low operation must not be continued frequency.

Operation cannot be sustained when the ratio of voltage to frequency, with these quantities given values per unit of their rated values exceeds un~tyby more than a small amount, for instance if V/f > 1 .l. The base of 'unit voltage' should be taken as the highest voltage for which the transformer is designed if a substantial rtse in system voltage has been catered for in the design. The condition does no1 call for high speed tripping; instantaneous operation is undesirable as this would cause tripping on momentary system disturbar~ces which can be borne safely, but normal conditions must b e restored or the transformer must be isolated within one or iwo minutes at most. The fundamental equation for the generat~onof e.m.f. in a transformer can be arranged to give:


8.

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Transformer setiing Criteria & Tutorials Page 29 of 33

ii is necessary to detect a ratio of E l f exceeding unity, E and f being expressed in per unit values of rated quantities.The system voltage, as measured by a voltage transformer, is applied to a resistance to produce a proportionate current; this current, on being passed through a capacitor, produced a voltage drop which is proportional to the function in question, Elf, and hence to the flux in the power transformer. Feedback techniques are used in the type GTT relay to make the measured ratio accurate over a wide range of frequency and voltage.Two time delay outputs are given by auxiliary elements, each with multiple contacts. One element, the contact of which are used to effect a control operation to reclify the abnormal condition, operates after a pre-selected fixed,time delay between 0.5s and 1.0s or between 2s and 5 s. The second element is arranged to trip the supplies to the transformer after a pre-set time delay of 5s to 30s or 12s to 120s if the abncrmal condition persists. Overfluxing protection is mostly confined to generator-transformers for which the risks appear to be greatest, although overfluxing trouble has been known to occur for other transformers as well.

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USE OF INSTANTANEOUS OVERCURRENT SOiJQCf

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The use of instantaneous relays for the primary side of the transformer is recommended inorder to improve fault clearance time and enable a lower time multiplier setting on relays elsewhere on the system. The relay should have low transient overreach and be set to approximately 125% of the maximum through fault level of the transformer, in order to prevent operation for faults on the secondary side.

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Generator and Generator Transf - Protection

Generator and Generator-Transformer

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'The core of an electric power system is the generation. $.': - ~..'&.'.:<.'.: ~ ~ ~ ~ With the exception of emerging fuel cell and solar-cell $ , : ~ ; ~ ~ y : ~ ~ ~ - ~ ~ technology for power systems, the conversion o f the . fundamental energy into its electrical equivalent normally reqdires a 'prime mover' to develop mechafiical power as an intermediate stage.

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The nature of this machine depends upon the source of energy and i n turn this has some bearing on the design o f the generator. Generators based on steam, gas, water or wind turbines, and reciprocating combustion engines are all i n use. Electrical ratings extend from a f e w hundred kVA (or even less] for reciprocating engine and renewable energy sets, up t o steam turbine sets exceeding 1200MVA. Small and medium sized sets may be directly connected to a power distribution system. A larger set may be associated with an individual transformer, through which it is coupled to the EHV primary transmission system. Switchgear may or may not be provided between t h e generator and transformer. In some cases, operational and economic advantages can be attained by providing a generator circuit breaker i n addition to a high voltage circuit breaker, but special demands will be placed on the generator circuit breaker for interruption o f generator fault current waveforms that do not have an early zero crossing. A unit transformer may be tapped o f f t h e interconnection between generator and transformer for the supply of power to auxiliary plant, as shown i n Figure 17.1. The unit transformer could be of the order of 10% of the unit rating for a large fossil-fuelled steam set with additions( flue-gas desulphurisation plant. b u t it may only be of the order o f 1% o f unit rating for a hydro set.

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required. The amount of protection applied w i l l be governed b y economic considerations, t a k i n g i n t o account the value of the machine, and t h e value o f its output t o the plant owner.

Main ttansformcr

Generator

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The following problems require consideration f r o m the point o f view o f applying protection: a. stator electrical faults

,' Auxiliary -.-supplics switchboard :

b. overload

d. unbalanced loading Industrial or commercial plants w i t h a requirement for steamlhot water n o w often'include generating plant utilising or producing steam t o improve overall economics, as a Combined Heat and Power (CHP) scheme. The plant w i l l typically have a connection t o the public Utility distribution system, and such generation is referred t o as 'embedded' generation. The generating plant may b e capable of export nf w r p l u s power, or simply reduce the i m p o r t o f power from the Utility. This is shown i n Figure 17.2.

e. overfluxing

f. inadvertent energisation e. rotor electrical faults

f. loss o f excitat~on g. loss of synchron~sm h. failure o f prlme mover

j. lubrication oil failure I. overspeed~ng

m. rotor distortion n. difference i n expansion between rotating an stationan/ parts ........................................

o. excessive v i b r a t ~ o n PCC

Gcncra:or

p. core lamination faults

The neutral point of a generator is usually earthed facilitate protection of the stator winding and associat system. Earthing also prevents damaging transic overvoltages i n the event of an arcing earth fault ferroresonance.

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For HV generators, impedance is usually inserted i n stator earthing connection t o limit the magnitude earth fault current. There is a wide variation i n the e: fault current chosen, common values being: 1. rated current

2 . 200A-400A (low impedance earthing] 3. IOA-20A (high impedance earthing)

A modern yencrating u n i t is a complex system comprising the generator stator winding, associated transformer and u n i t transformer (if present), the rotor w i t h its field winding and excitation system, and the prime mover w i t h its associated auxiliaries. Faults of many kinds can occur wi:hin this syslem for which diverse forms of electrical and mechanical protection are

The main methods of impedance-earthing a genet are shown i n Figure 17.3. Low values of earth ' current may limit the damage caused from a fault they simultaneously make detection of a fault tov the stator winding star point more difficult. Excel special applications, such as marine, LV generator normally solidly earthed t o comply w i t h s requirements. Where a step-up transformer is ap

-

the generator and the lower voltage winding o f the transformer can be treated as an isolated system that is not influenced by the earthing requirements o f the power system.

sufficient that the transformer be designed to have a primary winding knee-point e m f . equal t o 1.3 times the generator rated line voltage.

Failure of the stator windings or connection insulation can result in severe damage to the windings and stator core. The extent of the damage will depend on the magnitude and duration of the fault current.

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An earthicg transformer or a series impedance can be impedance. If an earthing transformer is ntinuous rating is usually in the range 5250kVA. The secondary winding is loaded with a resistor of a value which, when referred through the rransformrr turns ratio, will pass the chosen short-time earth-fault current. This is typically i n the range of 5-20A. The resistor prevents the production o f high transient overvoltages i n the event of an arcing earth fault, which i t does by discharging the bound charge i n the circuit Capacitance. For this reason, the resistive component of fault current should not be Icss. than the residual Capacitance current. This is the basis of the design, and in practice values of between 3-5 I,,, are used. It is .important that the earthing transformer never

'

becomes saturated; otherwise a very undesirable Condition of ferroresonance may occur. The normal rise ofthe generated voltage above the rated value caused by a sudden loss of load or by field forcing must be as well as flux doubling in the transformer point-on-wave o f voltage application. 11 is

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The most probable mode of insulation failure is phase to earth. Use of an earthing impedance limits the earth fault current and hence stator damage. An earth fauit involving the stator core results in burning of the iron at the point of fault and welds laminations together. Replacement of the faulty conductor may not be a very serious matter (dependent on set rating/voltage/construction) but the damage to the core cannot be ignored, since the welding o f laminations may result in local overheating. The damaged area can sometimes be repaired, but i f severe damage has occurred, a partial core rebuild will be necessary. A flashover is more likely to occur in the end-winding region, where electrical stresses are highest. The resultant forces on the conductors would be very large and they may result in extensive damage, requiring the partial or total rewinding o f the generator. Apart from burning the core. the greatest danger arising from failure to quickly deal with a fault is fire. A large portion of the insulating material is inflammable, and in the case of an air-cooled machine, the forced ventilation can quickly cause an arc flame to spread around the winding. Fire will not occur in a hydrogen-cooled machine, provided the stator system remains sealed. In any case, the length of an outage may be considerable, resulting in major financial impact from loss of generation revenue and/or import o f additional energy.

Phase-phase faults clear o f earth are less common; they may occur on the end portion of stator coils or in the slots if the winding involves two coil sides i n the same slot. In the latter case, the fault will involve earth i n a very short time. Phase fault current is not limited by the method of earthing the neutral point.

lnterturn faults are rare, but a significant fault-loop current can arise where such a fault does occur.

Conventional generator protection systems would be blind t o a n interturn fault, b u t the extra cost and complication of providing detection of a purely interturn fault is n o t usually justified. I n this case, an interturn fault must develop into an earth fault before it can be c!eared. An exception may be where a machine has an abnormally complicated or multiple winding arrangement, where the probqbility o f an interturn fault might be increased.

calculation, after measurement of the individual q : secondary currents. I n such relay designs, there is full.: galvanic separation o f the neutral-tail and terminal Q.; secondary circuits, as indicated i n Figure 17.5(a). This is not the case for the application of high-impedance differential protection. This difference can impose some special relay design requirements t o achieve s t a b i l i t y f ~ ~ , biased differential protection i n some applications. .@

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To respond quickly t o a phase fault w i t h damaging heavy current, sensitive, high-speed differential protection is normally applied t o generators rated in excess of 1MVA. For large generating units, fast fault clearance will also maintain stability of the main power system. The zone of differential protection can be extended t o include an associated step-up transformer. For smaller generators, IDMT/instantaneous overcurrent protection is usually the only phase fault protection applied. Sections 17.5-17.8 detail the various methods that are available for stator winding protection.

The relay connections for this form of protection are shown in Figure 17.5(a) and a typical bias characteristic is shown i n Figure 17.5(b). The differential current threshold setting I,, can be set as low as 5% o f rated :. generator current, to provide protection for as much of: the winding as possible. The bias slope break-point$& threshold setting I;, would typically be set t o a value.?$, above generator rated current, say 12O01o, to achieve::?. , external fault stability i'n the event of transient,{2 asymmetric CT saturation. Bias slope I;, setting would:? - ! typically be set at 150%. > .: c:

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The theory o f circulating current differential protection is discussed fully in Section 10.4. Stator

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High-speed phase fault protection is provided, by use of the connections shown i n Figure 17.4. This depicts the derivation of differential current through CT secondary circuit connections. This protection may also offer earth fault protection for some moderate impedance-earthed applications. Either biased differential or high impedance differential techniques can be applied. A subtle difference w i t h modern, biased. numerical generator protection relays is that they usually derive the differential currents and biasi'ng currents by algorithmic i

This d~ffersfrom biased differential protection by manner in which relay stability is achieved for eXt faults and by the fact that the differential current be attained through the electrical connections secondary circuits. I f the impedance of each re Figure 17.4 is high, the event oC one CT bec saturated by the through fault cutrent (leadin!

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latively low CT impedance), will allow the current from unsaturated CT t o flow mainly through the saturated rather than through the relay. This provides the uired protection stability where a tuned relay element is employed. I n practice, external resistance is added t o the relay circuit i o prwidc the necessary high impedance. The principle of high-impedance protection application is illustrated i n Figure 17.6, together with a summary of the calculations required t o determine ttie value o f external stabilising resistance.

To calculate the primary operating current, the following expression is used:

I,, = N X(is, + nl,) where:

lop = prima y operating current

N = CT ratio ls = relay l setting

n = number of CT's in parallel with relay element I, = CT magnetising currerft at

i

Hcalthy CT

Saturated CT

*I L', = K V ,

wherc J . O < K r l . S Stabilising resistor, R,, limits spill currcnt to
-

5I - R R r:lay

-

burden

I,, is typically set to 5% of generator rated secondary current.

It can be seen from the above that the calculations for the application of high impedance differential protection are more complex than for biased differential protection. However. the ~rotectionscheme is actually cuite simple and it bffers high level of stability for through f a k and external switching events.

a

With the advent of multi-function numerical relays and with a desire to dispense with external components; high impedance differential protection is not as popular as biased differential protection i n modern relaying practice. . . . . .

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i n some applications, protection may be required to limit voltages across the CT secondary circuits when the differential secondary current for an internal phasc fault flows through the high impedance relay circuit(s1, but this is not commonly a requirement for generator differential applications unless very high impedance relays .are applied. Where necessary, shunt-connected. non-linear resistors, should be deployed, as shown in

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Many factors affect this, including the other protection functions fed by the CT's and the knee-point requirements of the particular relay concerned. Relay manufacturers are able to provide detailed guidance on this matter.

A common connection arrangement for large generators is to operate the generator and associated step-up transformer as a unit without any intervening circuit breaker. The unit transformer supplying the generator auxiliaries is tapped off the connection between generator and step-up transformer. Differential protection can be arranged as follows.

i

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The CT requirements for differential protection will vary according t o the relay used. Modern numerical relays may not require Ci's specifically designed for differential protection to IEC 60044-1 class PX (or BS 3938 class X). However, requirements i n respect of CT knee-point voltage will still have to be checked for the specific relays used. High impedance differential protection may be more onerous i n this respect than biased differential protection.

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transformer rating is extremely low in relation to th

Dlffc-rcntial Protection

generator rating, e.g. for some hydro applications. ~h location of the third set o f current transformers normally on the primary side of the unit transformer. located on secondary side of the unit transformer, th( wnuld have-to- be of an exceptionally high ratio, : exceptionally high ratio interposing CT's would have. be used. Thus, the use of secondary side CTs is not to I recommended. Cne advantage is that unit transform faults would be' within the zone of protection of

,','

The generator stator and step-up transformer can be .. . . . _. ~ protected ~ ~ by . ~ a single i ~ ~ zone- of ~ overall ~ differential ... k:z:4>$;t. !...:1.+.,.. .., .,.. . % . protection (Figure 17.8). This will be in addition to :....:. :.. . differential protection applied to the generator only. The . .,.- ..< .. current transformers should be located in the generator . .... ... . neutral connections- and i n the -transformer HV ..... connections. Alternatively, C r s within the HV . . .. ..c:~$~..~;: ...: ::.: ..c %.a+-:,'.

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switchyard may be employed if the distance is not technically prohibitive. Even where there is a generator circuit breaker, overall differential protection can still be provided i f desired.

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generator. However, the sensitivity of the generat would protection to unit transformer phase faults considered inadequate, due to the relatively low rating the transformer in relation to that of the generat Thus, the unit transformer should have its 0,

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The current transformers should be rated according to Section 16.8.2. Since a power transformer is included .rwithin the zone o f protection, biased transformer differential protection, with rnagnetising inrush restraint z should be applied, as discussed in Section 16.8.5. C3 Transient overfluxing of the generator transformer may arise due to overvoltage following generator load rejection. In some applications, this may threaten the . stability of the differential protection. In such cases. .. -:,:.., is::.: consideration should be given to applying protection . ...,. ....,pv.j* *&-. with transient overfluxing restraintlblocking (e.g. based . . ..z.'-..$' . on a 5th harmonic differential currentthreshold). : Protection against sustained overfluxing is covered i n Section 17.14. C L

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protection phase For larger gener Overcurrent protection can be applied as remote ba ~rotection,to disconnect the unit from any uncl external fault. Where there is only one set of differ main protection, for a smaller generator, the OverC protection will also provide local back-up protecti the protected plant, i n the event that the protection fails t o operate. The general princi~ setting overcurrent relays are given in Chapter 9.

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time-delayed plain overcu protection to generators. For generators rated less lMVA, this will form the principal stator wi'

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principle form of protection for small generaton,. back-up for larger ones where differer protection. is used asthe primaty method of ge&i stat0.i winding protection. Voltage dep;nc ovekcurrent protection may tie applied where differel protection isnot justified on larger generators, or w problems are met i n applying plain overcur protection.

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Overcurrent protection of generators may take : forms. Plain overcurrent protection may be used a;

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busbars

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transformer

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.differential protection scheme. Protection for the u transformer is covered in Chapter 16, including methc for stabilising the protection against magnetising inn conditions.

Main

Generator

-

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In the case of a single generator feeding an i: system, current transformers at the neutral end machine should energise the overcurrent protect allow a response to winding fault conditions. characteristics should be selected to take into ; the fault current decrement behaviour of the ge

The current taken by the unit transformer must be allowed for by arranging the generator differential protection as a three-ended scheme. Unit transformer current transformers are usually applied to balance the generator differential protection and prevent the unit transformer through current being seen as differential current. An exception might be where the unit -

with allowance for the performance of the ex

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+tern and its field-forcing capability. Without the provision o f fault current compounding from generator CT's, an excitation system that is powered from an wcitation transformer a t the generator terminals will whibit a pronounced fault current decrement for a terminal fault. With failure t o consider this effect, the potential exists for the initial high fault current to decay to a value below the overcurrent protection pick-up setting before a relay element can operate, unless a low current setting and/or time setting is applied. The protection would then fail to trip the generator. The settings chosen must be the best compromise between assured operation i n the foregoing circumstances and discrimination with the system protection and passage of normal load current, but this can be impossible with plain overcurrent protection. In the more usual case o f a generator that operates i n parallel with others and which forms part o f an extensive interconnected system, back-up phase fault protection for a generator and its transformer will be provided by HV overcurrent protection. This will respond to the higherlevel backfeed from the power system to a unit fault. Other generators i n parallel would supply this current and, being stabilised by the system impedance, it will not suffer a major decrement. This protection is usually a requirement of the power system operator. Settings must be chosen to prevent operation for external faults fed by .the generator. I t is common for the HV overcurrent protection relay t o provide both time-delayed and instantaneous high-set elements. The time-delayed elements should be set t o ensure that the protected items of plant cannot pass levels o f through fault current i n excess o f their short-time withstand limits. The instantaneous elements should be set above the maximum possible fault current that the generator can supply, but less than the system-supplied fault current in the event of a generator winding fault. This back-up protection will minimise plant damage in the event of main protection failure for a generat~ngplant fault and instantaneous tripping for an HV-side fault will aid the recovery of the power system and parallel generation.

The choice depends upon the power system characteristics and level of protection t o be provided. Voltage-dependent overcurrent relays are often found applied t o generators used on industrial systems as an alternative to full differential protection.

Voltage controlled overcurrent protection has t w o timelcurrent ciiaracteristics which are selected according t o the status of a generator terminal voltage measuring element. The voltage threshold setting for the switching element is chosen according t o the following criteria. 1. during overloads,

when the system voltage is sustained near normal, the overcurrent protection should have a current setting above full load current and an operating time characteristic that will prevent the generating plant from passing current to a remote external fault for a period i n excess o f the plant shorttime withstand limits

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an external circuit. fault that.kill . .. . assist . - .. with:gradi?g

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Typical characteristics are shown i n Figure 17.9.

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Currcnr pick-up k v c l

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The plain overcurrent protection setting difficulty referred to i n the previous section arises because allowance has to be made both for the decrement of the generator fault current with time and for the passage of full load current. To overcome the difficulty of discrimination. the generator terminal voltage can be measured and used to dynamically modify the basic relay currentltime overcurrent characteristic for faults close to the generating plant. There are two basic alternatives for the application of voltage-dependent overcurrent Protection, which are discussed in the following sections.

5-*

2. under close-up fault conditions, the busbar voltage .must fall below the voltage threshold so that the second protection characteristic will be selected. This characteristic ihould be set t o allow relay operation ' with fault current decrement for a close-up fault a t the generator terminals or- a t the,HV- b u s b a .~ T h e . ~ ~ , ~ , & ; : ..:~~: .....24y.-i: 0 ,-.. .' . . protection . . . . .sh&d .. also ..time~jrade..'.with:~xteI??l~...... 'i.=:;". .. protection..~~&ie jy&-be.gdditiond i"fe&ds t o I ~ ~ ~ ~ ~ : ' - : , . . ~ '

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The alternative technique is to continuously vary the relay element ,pickup setting with generator voltage variation between upper and lower limits. The voltage is said to restrain the operation o f the current element. The effect is to. provide a dynamic I.D.M.T. protection characteristic, according to the voltage a t the machine

.

-
terminals. Alternatively, the relay element may be regarded as an impedance type with a long dependent time delay. In consequence, for a given fault condition, the relay continues t o operate mnre or less independently of current decrement i n the machine. A typical characteristic is shown i n Figure 17.10.

considerations.

This method is used i n the following situations:

a. direct-connected generators operating i n parallel b. generators with high-impedance neotral earthin, the earth fault current being limited to a few ter of amps c. installations where the resistance of the grour fault path is very high, due to the nature of t[ ground In these cases, conventional earth fault protection described i n Section 17.8.1.1 is of little use.

5 2

V ,

The principles o f sensitive earth fault protection ; described i n Sections 9.17.1. 9.18 and 9.19. The ea: fault (residual] current can be obtained from residl connection of line CT's, a line-connected CBCT, or a 0 the generator. neutral. The latter is not possible directional protection is used. The polarising voltagt usually the neutral voltage displacement input to . relay, or the residual o f the three phase voltages, s. suitable VT must be used. For Petersen Coil earthin! wattmetric technique {Section 9.19) can also be usec

Voltage level

Earth fault protection must be appl~edwhere impedance earthing is employed that limits the earth-fault current t o less than the pick-up threshold of the overcurrent andlor differential protection for a fault located down to the bottom 5% o f the stator winding from the starpoint. The type of protection required will depend on the method of earth~ngand connection of the generator to the power system

A single direct-connected generator operating on an isolated system will normally be directly earthed. However, i f several direct-connected generators are ' 17*. . operated in parallel, only one generator is normally ... For the unearthed generators, a ...\!. .... . . earthed a t a time. ........ . .:..i",':;,.simple measurement of the neutral current is not possible, and other methods of protection must be used. ~. . . The following sections describe the methods available. .,t,.

With this form of protection, a current transformer i n the neutral-earth connection energises an overcurrent relay element. This provides unrestricted earth-fault protection and 'so i t must be graded with feeder protection. The relay element will thereforfhave a zimedelayed operating characteristic. Grading must be carried out in accordance with the principles detailed in Chapter 9. The setting should not be more than 33°/~of the maximum earth fault current of the generator, and a lower setting would be preferably, depending on grading

. For 'direct '&nnected. -

operating in. para earth: fault :protection. may necessary. This is t o ensure that a faulted ge&rat~r be tripped. before there is any ossibility of the:+ ~ " e r c u r r e n tprotection tripping a parallel he; generator. When being driven by residually-conne phase CT's, the protection must be stabilised ag; incorrect tripping with transient spill current i n thee of asymmetric CT saturation when phase faul magnetising inrush current is being passed. Stabil techniques include the addition o f relay ci impedance and/or the application of a time delay. W the required setting o f the protection is very lo comparison t o the rated current of the phase C would be necessary to employ a single CBCT for the fault protection to ensure transient stability.

. directional'..&nsitive

Since any generator i n the paralleled group m: earthed, all generators will require to be fitted wit1 neutral overcurrent protection and sensitive direc earth fault protection. The setting o f the sensitive directional earth protection is chosen to co-ordinate with ger differential protection andlor neutral v displacement protection t o ensure that 95% of thc winding is protected. Figure 17.11 illustrat, complete scheme, including optional blocking where difficulties i n co-ordinating the generat downstream feeder earth-fault protection occur.

)-315

17/06/02

Page 285

10:46

As the protection is still unrestricted, the voltage setting

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o f the relay must be greater than the effective setting o f any downstream earth-fault protection. It must also be time-rirlavrri rn-nrriinatr w i t h c ~ r r h n ..... ,-- tn ........................ '. r .n. t r r t i n n Sometimes, a second high-set element with short time delay is used t o provide fast-acting protection against major winding earth-faults. Figure 17.12 illustrates the possible connections that may be used.

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c,

figorc 77. ll: CC~??M):C.~S;;~ rcrr:.?-c?uli pr8>:wrifir;S C I I C V ~:CI:C , ; , : c c I - ~ - , ; , I : ; ~ ,c~ . ~ c

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For cases (b) and (c) above, it is not necessary t o use a directional facility. Care must be taken t o use the correct RCA setting - for instance if the earthing impedance is mainly resistive, this should be 0". On insulated or very 1 . : . ' .,-.hig.h impedance earthed systems, an RCA o f -90" would :,'.?-.-be . :used, as the .earth fault current is -predominately =

.

.-2: . -.. ... :.:~irectional .,-

sensitive earth-fault protection can also be used for detecting winding earth faults. I n this case, the . relay element is applied t o the terminalsof the generator and is set to respond t o faults only within the machine windings. Hence earth faults o n the external system do not result i n relay operation. However, current flowing from the system into a winding earth fault causes relay operation. It will not operate on the earthed machine, so that other types of earth fault protection must also be applied. All generators must be so fitted. since any can be operated as the earthed machine.

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@ Ocrivcd from phasc ncutral voltagcs @ Measurcd from carth impcdancc @ Mcasurcd from brokcn dclta VI

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In a balanced network, the addition of the three phaseearth voltages produces a nominally zero residual . voltage, since there would be little zero sequence voltage Present. Any earth fault will set up a zero sequence system voltage, which will give rise t o a non-zero residual voltage. This can be measured by a suitable relay element. The voltage signal must be derived from a VT that is suitable - i.e. it must be capable of transforming zero-sequence voltage, so 3-limb types and those without a primary earth connection are not suitable. This unbalance provides a means of detecting earth faults. The element be 'nsensitive third harmonic voltages that may be Present in the system as these will

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As noted in Section 17.2, a directly-earthed generatortransformer u n i t cannot interchange zero-sequence current with the remainder o f the network, and hence an earth fault protection grading problem does n o t exist The following sections detail the protection methods for the various forms of impedance earthing of generators. . . . . , . ... ..I. _ .. .. . .. . .

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A current transformer mounted on the neutral-earth 17 conductor can drive an instantaneous and/or time delayed overcurrent relay element, as shown i n Figure 17.13. I t is impossible to provide protection for the whole of the winding, and Figure 17.13 also details how the percentage of winding covered can be calculated. For a relay element with an instantaneous setting, protection is typically limited t o 90% of the winding. This is t o ensure that the protection will not maloperate w i t h zero sequence current during operation of a primary fuse for a ........ ...... . W earth fault or with any transient surge currents that . , -. could flow through the interwinding capacitance of the . . . . . ..,,.,... ........ , .. .: .; . .-"?.-.;: ,,step-up transformer for an HV system earth fault.

. - . . . .-:;;.;.\.'..

A time-delayed relay ismore secure i n this respect, and if ,.; . may have a ~ t t i n gto cover 9% of the stator winding. Since the generating units under consideration are usually large, instantaneous and timedelayed relay elements are

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Chap11-280-315

11/06/02

Page 290

10:46

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often applied, with settings of 10% and 5% of maximum current respectively; this is the optimum ,*:,** ...... : compromise i n performance. The portion of the winding ..& .z,..... :,.>' .. :..-c<. .'-. :...v ;',. :. left unprotected for an earth fault is a t the neutral end. @ !"" ..-., C.,?.A,: -.: .i.::::$,:<, >::?~ 2 . +.:+.. .,.:~;i. Since ..:,.-.. the voltage t o earth a t this end of the winding is :... .;> ..::<,.. ,.. '.;a-. ........... 2%: . ,.. low, the probability of an eartn fauit occurring is also lo^. . .. . . ~ .;. ............ : . . . Hence additional protection is often not applied. . ,. ' "

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In this arrangement, shown in Figure 17.14(a), the generator is earthed via the primary winding of a distribution transformer. The secondary winding is fitted with a loading resistor to limit the earth fault current. An overcurrent relay element energised from a current transformer connected i n the resistor circuit is used to measure secondary earth fault current. The relay should have an effective setting equivalent to 5% of the maximum earth fault current at rated generator voltage, i n order to protect 95% of the stator winding. The relay element response to third harmonic curre_nt should be limited to prevent incorrect operation when a sensitive setting is applied.

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Earth fault protection can also be provided using a voltag measuring element i n the secondary circuit instead. ;T. setting considerations would be similar to those for:$ current operated ~ ~ o t e c t ~ obut n * transposed to voltat The circuit diagram is shown i n Figure 17.l4(b). .; Application of both voltage and current opera. elements to a generator with distribution transfon earthing provides some advantages. The curr operated function will continue to operate i n the ev of a short-circuited loading resistor and the volt protection still functions in the event of an OF circuited resistor. However, neither scheme will ope i n the event of a flashover on the primary terminal the transformer or of the neutral cable between generator and the transformer during an earth faul CT could be added in the neutral connection closet, generator, to energise a high-set overcurrent elerne pro' detect such a fault, but the fault current high enough to operate the phase differ< protection.

As discussed i n Section 17.8.2.1 for neutral overcurrent protection, the protection should be time delayed when in order to prevent a sensitive setting is maloperation under transient conditions. It also must grade with generator VT primary protection (for a, VT primary earth fault). An operation time i n the range 0.5s-3s is usual. Less sensitive instantaneous protection can also be applied to provide fast tripping for a heavier earth fault condition.

. .

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gcncrator stator winding using a currcnt clcmcnt - ..

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This can be applied in the same manner as for c connected generators (Section 17.8.1.3). The

190

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: :

-280-315

17/06/02

Page 2 9 1

10:46

rence is that 'the are no grading problems as the protection is inherently restricted. A sensitive setting . can therefore be used, enabling cover o f up t o 95% of the stator winding t o be achieved.

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17.t3.3 Rcs:rir';ccl

This technique can beused on small generators not fitted with differential protection to provide fast acting earth fault protection within a defined zone that encompasses the generator. It is cheaper than full differential protection but only provides protection against earth faults. The principle is that used for transformer REF protection, as detailed in Section 16.7. However, in contrast t o transformer REF protection, both biased lowimpedance and high-impedance techniques can be used. ... !/ .,......... !'<;--:": .... ".":' ,I:;.:!.,L::+>:: . : :.

.-,q.;

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This is shown i n Figure 17.15. The main advantage is that the neutral CT can also be used in a modern relay t o provide conventional earth-fault protection and no external resistors are used. Relay 'bias is required, as described i n Section 10.4.2, b u t the formula for calculating the bias is slightly different and also shown in Fiqure 17.15. ..

..................................

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Phasc CT ratio 100011

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CT in the neutral connection. Settings of the order of 5010

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o f maximum earth fault current at the generator terminals are typical. The usual requirements i n respect of stabilising resistor and non-linear resistor to guard against excessive voltage across the relay must be taken, where necessary.

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All of the methods for earth fault protection detailed so far leave part of the winding unprotected. In most cases, this is of no consequence as the probability of a fault occurring in the 5010 of the winding nearest the neutral connection is very low,due to the reduced phase to earth voltage. However, a fault can occur anywhere along the stator windings in the event of insulation failure due to localised heating from a core fault. In cases where protection for the entire winding is required, perhaps for alarm only, there are various methods available. .

;.

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.

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r. 0

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2

s .f=

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One method is to measure the internally generated third harmonic voltage that appears across the earthing . impedance due to the flow o f third harmonic currents :.":c .-L'. through the shunt capacitance b f t h e windings : . . . . etc. When a fa'ult occurs in.the p a r t o f the stator winding nearest the neutral end, the third harmonic % voltage drops to near zero, and hence a relay element r: that responds to third harmonic voltage can be used t o 0 detect the condition. As the fault location moves + progressively away from the neutral end, the drop in 2 third harmonic voltage from healthy conditions becomes less, so that at around 20-30010 of the winding distance, it no longer becomes possible to discriminate between a healthy and a faulty winding. Hence, a conventional earth-fault scheme should be used i n conjunction with a 17 third harmonic scheme, to provide overlapping cover of the entire stator winding. The measurement o f third harmonic voltage can be taken either from a star-point VT or the generator line VT. In the latter case, the VT must be capable of carrying residual flux, and this prevents the use of 3-limb types. I f the third harmonic voltage is measured at the generator star point, an undewoltage characteristic is used. An ovewoltage characteristic is used i f the measurement is taken from the generator line VT. For effective application of this - .: . form of protection, there should be a t least 1010 third :-.-.;.. harmonic voltage across the generator neutral earthing i....::::; .. :..,: -,.:.. :, impedance under all operating conditions. ....

sl. 2

I,

3 I,,,,

-

IN

(highrst of 1,. IS. I C J +(INx scoiina.foctorJ

u.hrrr scnlit~gfactor

-

2

nrurral

phnriTT

C T ratio

--200 1000

0.2

The initial bias slope is commonly set t o 0%to provide maximum sensitivity, and applied up to the rated current of the generator. I t may be increased to counter the effects of CT mismatch. The bias slope above generator rated current is typically set to 150% o f rated value. The initial current setting is typically 5qo of the minimum earth fault current for a fault a t the machine terminals. -

*!.7.<.q :. .

p ;..... : , , , : . ...., ,..... I , ,?.. . :,. 18,

....... ::: :.!.<::::,,::.:.#c.

-

The principle of high impedance differential protection is given in Chapter 10 and also described further in Section 17-52. The same technique can be used for earth-fault

. ..

n,

.r

G

l1

.

o

;

., .

A problem encountered is that the level o f third harmonic voltage generated is related to the output of the generator. The voltage is low when generator output

'

-

*

-

,-

-315

17/06/02

10:46

+

Page 292

i s low. I n order t o avoid maloperation when operdting at low power output, the relay element can be inhibited using an overcurrent or power element (kW, kvar or kVA) and internal programmable logic. ; y,
I

i

--0

--

)r

9.

'1

Another method for protecting the entire stator winding of a generator is t o deploy signal injection equipment to inject a low frequency voltage between the stator star point and earth. An earth fault at any winding location will result i n the flow of a measurable iniection current t o cause protection operation. This form of protection can provide earth fault protection when the generator is a t standstill, prior t o run-up. It is also an appropriate method t o apply t o variable speed synchronous machines. Such machines may be employed for variable speed motoring i n pumped-storage generation schemes or for starting a large gas turbine prime mover.

I

.

... . . ., . , . . . . .,. . .:.'.(,. > , ........ LS2%j:;<:;>;. :,.>f.:j<>,:..., ,"

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,,.:

i

z.

0

*

mach~newith a healthy voltage regulator, but i t may be caused by the fol!owing cont~hgencies.

"ct E

c:

a. defective operation of the automatic voltage regulator when the machine is i n isolated operation

r,

.-. 0

b. operation under manual control with the voltage regulator out of service. A sudden variation of the load, i n particular the reactive power component. will give rise to a substantial change i n voltage because of the large voltage regulatinn inherent in a typical alternator

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.,.

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.'-

.

.

:

c. sudden loss of load (due to tripping of outgoing feeders, leaving the set isolated or feeding a very small load) may cause a sudden rise in terminal voltage due to the trapped field flux and/or overspeed Sudden loss of load should only cause a transient overvoltage w h ~ l ethe voltage regulator and governor act to correct the situation. A maladjusted voltage regulator may trlp to manual, ma~ntalnlngexcitation a t the value prior to load loss while the generator supplies little or no load. The terminal voltage will increase substantially, and i n severe cases i t would be limited only by the saturation characteristic of the generator. A rise in speed simply compounds the problem. I f load that is sensitive to overvoltages remains connected, the consequences i n terms of equipment damage and lost revenue can be

. a -

, A,,.

severe.

l%; 2;;.

ford

. -A I s ..

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. A sustained overvoltage condition should not occur for a

Q

.

:

Overvoltages on a generator may occur due t o transient surges on the network, or prolonged power frequency overvoltages may arise from a variety of conditions. Surge arrestors may be required t o protect against transient overvoltages, but relay protection may be used to protect against power frequency overvoltages.

.a

.

. >.>. ..

. I . .; . ': ,. : .

C,

For these reasons, it is prudent to provide powerx frequency overvoltage protection, i n the form of a timedelayed element, either IDMT or definite time. The time *; . delay should be long enough t o prevent operation during .~.normal regulator action, and therefore should take ;V account of the type of AVR fitted and its transient ,;:. response. Sometimes a high-set element is provided as j - .. .>., well, w i t h a very short definite-tirne delay !?+ instantaneous setting t o provide a rapid trip in extreme<:$ circumstances. The usefulness of this is questionable generators fitted with an excitation system other than static type, because the excitation will decay in$ accordance with the open-circuit time constant of the;:: field winding. This decay can last several seconds. The-j relay element is arranged to trip both the main circuit, breaker (if not already open) and the excitation; trippingL! the main circuit breaker alone is not sufficient.

Prolonged overvoltages may also occur on

'5:

.

.

.

,

ii

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Undervoltage protection i s rarely fitted to generators. l t is sometimes used as an interlock element for anothe protection function or scheme. such as field failu.6; protection or inadvertent energisation protection,.+yheg the abnormality t o be detected leads -directly$... . -. ... indirectly to an undervoltage condition. . . . ..-. q, . -.. ...

A transmission system u n d e ~ o l t a g econdition may arix when there is insufficient reactive power generation to maintain the system voltage profile and the conditior must be addressed to avoid the possible phenomenon system voltage collapse. However, i t should be addressed by the deployment o 'system protection' schemes. The generation should no be tripped. The greatest case for undervoltage protectio being required would be for a generator supplying a isolated power system or to meet Utility demands fl connection of embedded generation (see Section 17.21 In the case of generators feeding an isolated systei undervoltage may occur for several reasons, typica overloading or failure of the AVR. In some cases. t performance of generator auxiliav plant fed via a u transformer from the generator terminals could adversely affected by prolonged undervoltage. Where undervoltage protection is required, it sho comprise an undervoltage element 'and an associa time delay. Settings must be chosen t o a\ maloperation during the inevitable voltage dips du, power system fault clearance or associated with m1 starting. Transient reductions in voltage down to 80' less may be encountered during motor starting.

7-280-315

17/06/02

10:46

-

Page 2Sf

,

.

LOV.; FOR;hJ;;RC

;7.!1

F-<,'>;ERj~Fb~E:t5z PC'.

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,Low forward power or reverse power protection may be required for some generators to protect the prime mover. Parts o f the prime mover may not be designed t o experience reverse torque or they may become damaged throuqh continued rotation after the prime mover has suffered some form o f failure.

Low forward power protection is often used as an interlocking function to enable opening of the main circuit breaker for non-urgent trip< - e.g. for a stator earth fault on a high-impedance earthed generator, or when a norinal shutdown o f a set is taking place. This is to minimise the risk o f plant overspeeding when the electrical load is removed from a high-speed cylindrical rotor generator. The rotor of this type o f generator is highly stressed mechanically and cannot tolerate much overspeed. While the governor should control overspeed conditions, it is not good practice t o open the main circuit breaker simultaneously with tripping of the prime mover for non-urgent trips. For a steam turbine, for example, there is a risk o f overspeeding due to-energy -storage i n the trapped steam, after steam vaive tripping, :.:.orliri the.everlt that the steam valve(s1 do not fully close f o r some reason. For urgent trip conditions, such as .:stator differential protection operation, the risk involved in simultaneous prime mover and generator breaker tripping must be accepted.

I I

Dicxl Engine

i

5-25

(split shaft) Gas Tuhinc ...........

firclcrplosion due to unburnt fucl Mechanical damaqc

. . . . . . . .

0.2-2

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Hydro I

bladc and runncr cavitation

(bladcs in water)

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turbinc bladc damaqc gcarbox damayc on gcarcd XIS

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Reverse power protection is applied to prevent damage to mechanical plant items in the event o f failure of the prime mover. Table 17.1 gives details o f the potential problems for various prime mover types and the typical settings for reverse power protection. For applications

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A three-phase balanced load produces a reaction field tr that, to a first approximation, is constant and;;;o synchronously w i t h the rotor field system. unbalanced corfdition can be resolved into positive, negative and zero sequence components. The positive sequence component is similar t o the normal balanced load. The zero sequence component produces.no main

-- . . . . . . . . . . . - . . . . . . . . .

. I-

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,.

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armature reaction.

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The negative sequence compdnent i j similar: to, the- v$<$$:<{2' .~..;;.+y...~ ..:. .. positive . sequence .system,.-.except )that. .,=,. u : . f. reaction field rotates in -the.@p+ite direction t d t h 6 . d ; ~field system, Hence, a flux, is produced which cuts the:. -. .:'. rotor at twice the rotational velocity, thereby inducing ..

55

double frequency currents i n the field system and i n the rotor body. The resulting eddy-currents are very large and cause severe heating of the rotor.

A generator is assigned a continuous negative sequence rating. For turbo-generators this rating is low; standard values of 10% and 15% of the generator continuous rating have been adopted. The lower rating applies when the more intensive cooling techniques are applied, for example hydrogen-cooling with gas ducts i n the rotor to facilitate direct cooling of the winding.

gcarbox damage

(single *ah1

-

The reverse power protection should be provided with a definite time delay on operation to prevent spurious operation with transient power swings that may arise following synchronisation or i n the event of a power transmission system disturbance.

So severe is this effect that a single-phase load equal t o the normal three-phase rated current can quickly heat the rotor slot wedges to the softening point. They may then be extruded under centrifugal force until they stand above the rotor surface, when it is possible t h a t they may strike the stator core.

>M4Lo '

.................

where a protection sensitivity o f better than 3% is required, a metering class CT should be employed t o avoid incorrect protection behaviour due to CT phase angle errors when the generator supplies a significant level of reactive power a t close t o zero power factor.

Short time heating is of interest during system fault conditions and it is usual i n determining the generator negative sequence withstand capability to assume that the heat dissipation during such periods is negligible. Using this approximation i t is possible to express the heating by the law:

'e . O I-

.:::.-,

fft'\;. ; 3 , G.5

where:

sequence capacity and may not require protection.-,;@ Modern numerical relays derive the negative s e q u e n ~ current level by calculation, with no need for speIci circuits to extract the negative sequence component. A.'.& true thermal replica approach is often followed. to aliOw i.;$ >......... for:

$3

IZR = negative sequence component (per unit of MCR) t = time (seconds) K

= constant proportional

to the thennal capacity

of the generator rotor

-

a. standing levels of negative sequence current below the continuous withstand capability. This has the effect of shortening the time to reach the critial temperature after an increase in negative sequence current above the continuous withstand capability .'

For heating over a period of more than a few seconds, it is necessary to allow for the heat dissipated. From a combination of the continuous and short time ratings, the overall heating characteristic can be deduced to be:

a

b. cooling effects when negative sequence current levels are below the continuous withstand . capability The advantage of this approach is thz: cooling effects are modelled more accurately, but the disadvantage is that

k

u

Q.l

-P

%

L

U

where: =

-

the tripping characteristic m3Y not follow th; withstand characteristic specified by the manufacturer accurately. .,

Ilegarive PIIaSe requetlce corrrilluousratillg ill per unit of MCR

The typical relay element characteristic takes the form of ;:

The heating character;stics of various designs of generator are shown in Figure 17.16.

time to trip

.......... -1nd;rcctly

-. ................... > coolcd (air)

... lndircctly coolcd (H2)

;

350MW dircct coolcd j 660MW dircct coolcd i

:

-1000MW d~rcctcooled, Usmg I:t modcl Usmg truc thcrmal modcl

\I

.

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0.01 . . . . . . . . . . . . . . . 0.01 0.1 1 10 Ncgativc scqucncc currcnl (p.u.1

-

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.;

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fI m l o r qcr;r~irluri

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..:

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.'

:.

.?(;:;> ........ .:,,.......

. .:.,..;s.;.:; ., ..

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=

negative sequence witltstand coeficient (Figure 1 7.1 6)

IZcmr = generator maximum coittinuous Iz withstand Iflc I,

=

generator rated primary curretlr

=

CTpriinary current

IN

=

relay rated current

Figure 17.16 also shows. the thermal replica time

.... .L.

Kg

This protection is applied to prevent overheating due to negative sequence currents. Small -salient-pole generators have a P ~ ~ larger P negative ~

*

characteristic described by Equation 17.1, frorn which it.. will be seen that a significant gain in capability is achieved at low levels of negative sequence current' Such a protection element will also respond to phase-: earth and phase-phase faults where sufficient negative sequence current arises. Grading with downstream. power system protection relays is therefore required. A, definite minimum time setting must be applied to the negative sequence relay element to ensure grading. A maximum trip time setting may also be used ~ ~ ~ ~ ~ ~ ~ ~ ~ to ensure correcttripping when xquenF

-280-315

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Page 295

rrent level is only slightly i n excess of the continuous thstand capability and hence the trip time from the ay depart significantly from the rotor

Accidental energisation of a generator when it is not running may cause severe damage to it. With the generator a t standstill, closing the circuit breaker results in the generator acting as an induction motor; the field winding (if closed) and the rotor solid ironldamper circuits acting as rotor circuits. Very high currents are induced i n these rotor components, and also occur i n the stator, with resultant rapid overheating and damage. Protection against this condjtion is therefore desirable. A combination of stator undervoltage and overcurrent can be used t o detect this condition. An instantaneous overcurrent element is used, and gated with a threephase undervoltage element (fed from a VT on the generator side of the circuit breaker) t o provide the protection. The overcurrent element can have a low setting, as operation is blocked when the generator is ,;.;ioperating normally. The voltage setting should be low ;"enough t o ensure that operation cannot occur for -.' . .,transient fautts. - A setting of about 50% of rated voltage . :-,. is -typical. VT failure can cause maloperation o f the . . protection, so the element should be inhibited under these conditions.

These conditions are grouped together because these problems often occur due to a departure from synchronous speed.

: . .

2.: !.

Overfluxing occurs when the ratio o f voltage to frequency is too high. The iron saturates owing to the high flux density and results in stray flux occurring in components not designed to carry it. Overheating can then occur, resulting i n damage. The problem affects both direct-and indirectly-connected generators. Either excessive voltage, or low frequency, or a combination of both can result i n overfluxing, a voltage to frequency ratio i n excess of 1.05p.u. normally being indicative of this condition. Excessive flux can arise transiently, which is not a problem for the generator. For example, a generator can be subjected t o a transiently high power frequency voltage. at nominal frequency. immediately after full load rejection. Since the condition would not be sustained, it only presents a problem for the stability

L!. .

k-...- -..... -........... :

~

~

t

v ~ ~ r . t rr , ri i , m

.....

u

~ . r , - a r i a *

~ . i , r

.

of the transformer differential protection schemes applied a t the power station (see Chapter 16 for transformer protection). Sustained overfluxing can arise during run up, i f excitation is applied too early with the AVR i n service, or i f the generator is run down, w i t h the excitation still applied. Other overfluxing instances have occurred from loss of the AVR voltage feedback signal, due to a reference VT problem. Such sustained conditions must be detected by a dedicated overfluxing protection function that will raise an alarm and possibly force an immediate reduction i n excitation. . .:' . ., , i . .

...... Most AVRs' have an overfluxing protection facility - -.;$>. < ......... - .. .:;,.?, ....... .: -r..... .-..,?. . included. This may only be operative when the generator . . ,.: is on open circuit, and hence fail to detect overfluxing . : ; s : ~ . : . : .,:... . .,y:.:.h conditions due to abnormally low system frequency. " . p..;~::*-.:. .' . this facility is not engineered t o protection z....$ .... :.?~:.u. ..i. ::;. *,:,,. ,:- Q :: . relay standards, and should not be solely relied upon t o .,. r .1. ... 'Iprovide o v e k ~ u x i nprotection. ~ A separate relay element Y':>& is therefore desirable and provided i n most modern CI relays. E .,&

-

.:.z

ow ever,

$;%;z' :

,

-

.?

5.

I t is usual t o provide a definite time-delayed alarm setting and an instantaneous or inverse time-delayed trip setting, t o match the withstand characteristics o f the protected generator and transformer. It is very important that the VT reference for overfluxing : protection is not.the same as that.used.for the AVR. . . . :.

. . .

. . . . . .. . . . .. . .. .. . .. . . ? . . : > : .

t~

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....z...

.-

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&, . : - . W .

:.: :<;.

.

'

=

-

w

u

-

-%

The governor fitted to the prime mover normally provides protection against overfrequency. Underfrequency may occur as a result of overload of generators operating on an isolated system, or a serious fault on the power system that results in a deficit of generation compared to load. This may occur i f a grid system suffers a major fault on transmission lines linking two parts o f the system, and the system then splits into two. I t is likely that one part will have an excess of generation over load, and the other will have a corresponding deficit. Frequency will fall fairly rapidly i n the latter part, and the normal response is load shedding, either by load shedding relays or operator action. However, prime movers may have to be protected against excessively low frequency by tripping of the generators concerned.

r

2 2

17 -

W ~ t hsome prime movers, operation i n narrow frequency bands that lie close to normal running speed (either above or below) may only be permitted for short periods, together with a cumulative lifetime duration of .. ' . . . operation i n such frequency bands. This typically occurs ai,.:,.. ....... : due to the presence of rotor torsional frequencies in such ~ .... ~ frequency bands. In such cases, monitoring o f the period iij?.::: of time spent i n these frequency bands is required. A :'.,...:. . . special relay is fitted i n such cases, arranged t o provide alarm and trip facilities if either an inoividual or '

I- ,>-.

~

~

:hepl7-280-325

17/06/02

10:48

Page 2 9 6

cumulative period exceeds a set time.

produce a balancing force on this axis. The result is an unbalanced force t h a t in a large machine may be o f the order o f 50-100 tons. A violent vibration is set up that may damage bearing surfaces or even displace t h e rotor by an amount sufficient t o cause it t o foul the stator.

-

The field circuit of a generator, comprising the field winding of the generator and the armature o f the exciter, together w i t h any associated field circuit breaker if it exists, is an isolated d.c. c i r c u ~ twhich is not normally earthed. I f an earth fault occurs, there will be no steadystate fault current and the need for action will not be evident.

0

%.A

...

" 3 =c L

.=

I

i

where:

%.A

2Q

A = area

=

B

u

=

,.,:: . . .!r:!.;,!>.!>,: ,,. .,,,, . . . . . . . . .. ~ ;

A 'blind spot' would exist a t t h e centre o f the field winding. To avoid a fault at this location re,mainipg.,,.,. 'undetected., the tapping point d n the potentiometi$~~ could be varied b y a p u s h b u t t o ~o r switch:.. l~h%'i@l&j.*. . . . setting is typically about 5% o f the exciter.vol-tage.- . + :;.;. . . .

8rc

L

;><<>f<~,,,:.;,jg.:

This is a scheme that was fitted t o older generators, and it -is illustrated i n Figure 17.18. An earth fault on the field winding w o u l produce a voltage across the relay, the maximum voltage occurring for faults at the ends of the winding.

F=- B ' A

L

: >;-::;j;jit

; :

b. a.c. injection method . .. . .. :. .. . . ;

More damage may be caused mechanically. If a large portion o f the winding is short-circuited, the flux may adopt a pattern such as that shown in Figure 17.17. The attracting force at the surface o f the rotor is given by:

L

. . :,!. ; :<,<;;;<,!

a. potentiometer method

%.A

P

.

Two methods are available t o detect this type o f f a u l t The first method is suitable for generators that incorporate brushes in the main generator field windina: The second method requires at least a slip-ring connection t o the field circuit:

Danger arises if a second earth fault occurs at a separate point i n the field system, t o cause the high field current to be diverted, in part at least, from the intervening turns. Serious- damage t o the conductors and .possibly the rotor can occur very rapidly under these conditions.

= --

;.

,

.

flux density

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.

.

.

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o

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Two methods are in common use. The first is based on i low frequency signal injection, with series filtering, as :: shown in Figure 17.19(a). It comprises an injection::'. source that is connected between earth and one side the field circuit, through capacitive couplir~gand the.:; measurement circuit. The field circuit is subjected to a n j i alternating potential at substantially the same level;l throughout. An earth fault anywhere in thc ficld system': will give rise to a Current that is detekted as an;? equivalent voltage across the adjustable rcsistor by the.$ relay. The capacitive coupling blocks the normal d.~.fie143 voltage, preventing the discharge of a large d i r c ~ e current through thc protection scheme. T h c c o m b i n a t i ~ ? ~ ~

4,:r,..:,;,

wirh put:!~!+,.onrJl.cg thorl r,trv;l

,.,-

.. .. .,

.

.

I t will be seen from Figure 17.17 that the flux is concentrated on one pole but widely dispersed over the other and intervening surfaces. .[he attracting force is in consequence large on one pole but very weak on the axis will opposite one, while fluxon the

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1-280-315

I 1

17/06/02

10:48

-

Page 297

of series capacitor and reactor forms a low-pass tuned circuit. the intention being to filter higher frequency rotor currents that may occur for a variety of reasons.

17.1 5.2 Rotor Earth Faul? Proreaior? For 6rush;czs Gcr-erato:s

A brushless generator has an excitation system consisting of:

Other schemes are based on power frequency signal injection. An impedance relay element is used, a field winding earth fault reducing the impedance seen by the relay. These suffer the draw back of being susceptible to static excitation system harmonic currents when there is significant field winding and excitation system shunt capacitance.

1. a main exciter with rotating zrmatzre and

stationary field windings 2. a rotating rectifier assembly, carried on the main shaft line out

3. a controlled rectifier producing the d.c. field voltage for the main exciter field from an a.c. source (often a small 'pilot' exciter)

Greater immunity for such, systems is offered by capacitively coupling the protection scheme to both ends of the field winding, where brush or slip ring access is ~ossible(Figure 17.19(b)).

Hence, no brushes are required in the generator field circuit. All control is carried out in the field circuit of the main exciter. Detection of a rotor circuit earth fault is still necessary, but this must be based on a dedicated . : - $ ~ ~ . ~ ~ $ ; ? ~ rotor-mounted system that has a telemetry link to 'a- .' provide an alarmldata.

.j;;+zS;:-. .!.?p*y$@;:

The low-frequency injection scheme is also advantageous in that the current flow through the field winding shunt capacitance will be lower than for a power frequency scheme. Such current would flow through the machine bearings to cause erosion of the bearing surface. For power frequency schemes, a solution is to insulate the bearings and provide an earthing brush for the shaft.

'

L 'PI"

'

...:

'.

CI

.. j ..: : ,.. : ,. . ,,L..!.>. . .

:;!.#~:.:;!

!:.

,

.-: ,.....<....\:..

%= L

5

E: As detailed in Section 17.15 a shorted section of field 2 winding will result in an unsymmetrical rotor flux pattern and in potentially damaging rotor vibration. ... b . . .. & . -..: . ~etection of such an electrical fault is possible using a -;. *.. probe consisting of a coil placed i n the airgap. The flux. -1: .-ct.. . . . C-' . pittern i f t k positi"e and negative poles is me&ured". , 2C . and any significant difference in flux pattern between .".- PI the poles is indicative of a shorted turn or turns. 'U

,.

.

,

;;rator

I

'

winding

Automated waveform comparison techniques can be used to provide a protection scheme, or the waveform can be inspected visually a t regular intervals. An immediate shutdown is not normally required unless the effects of the fault are severe. The fault can be kept under observation until a suitable shutdown for repair can be arranged. Repair will take some time, since it means unthreading the rotor and dismantling the winding.

I.

L.F. injection

(a1 Low (rcqucn& a.c. voltage injection

- currcnt

mcarurcmcnt

Since short-circuited turns on the rotor may cause damaging vibration and the detection of field faults for all degrees of abnormality is difficult, the provision of a vibration a detection scheme is desirable - this forms part of the mechanical protection of the generator.

?J

.

t,

'1 0

2

5

0

- 17-

A short-circuited diode will produce an a.c. ripple in the exciter field circuit. This can be detected by a relay monitoring the current in the exciter field circuit, however such systems have proved to be unreliable. The relay would need to be time delayed to prevent an alarm being issued with normal field forcing during a power system fault. A delay of 5-10 seconds may be necessary. i C

,

-

197

-

+

.

.........

.. ,

,

.

, .,.,

1 1

Fuses t o disconnect the faulty diode after failure may be fitted. The fuses are of the indicating type, and an inspection window can be fitted over the diode wheel t o enable diode health t o be monitored manually.

P. dinde that fails open-circuit occurs less often. I f there is more than one diode i n parallel for each arm of the diode bridge. the only impact is t o restrict the maximum continuous excitation possible. If only a single diode per bridge arm i s fitted, some ripple will be present on the main field supply but the inductance of the circuit will smooth this t o a degree and again the main effect is t o restrict the maximum continuous excitation. The set can be kept running until a convenient shutdown can be arranged.

I

'

-

0 w

+r L.

17.I 5.5 i i c ' c

9 ,

s!,rl.?fiy;;o:.i -1'

0

The need t o rapidly suppress the field o f Ti'machine in which a fault has developed should be obvious, because as long as the excitation is maintained, the machine will feed its own fault even though isolated from the power system. Any delay i n the decay o f rotor flux will extend the fault damage. Braking the rotor i s n o solution, because of its large kinetic energy. The field - w i n d i n g current cannot b e interrupted .. .;: - ~ n ' s t a n t a q e o u ias l ~ i t fidws i n a highly inductive circuit. : - Consequently, the flux energy must b e ' dissipated'.to . ..i? '.prevent' ; an excessive- inductive voltage rise i n the field .: circuit. For machines of moderate size, it is satisfactory -,: to open the field circuit with a n air-break circuit breaker -.-

without arc blow-out coils. Such a breaker permits only a moderate arc voltage, which is nevertheless high enough t o suppress the field 'current fairly rapidly. The inductive energy is dissipated partly i n the arc and partly in eddy-currents in the rotor core and damper windings. With generators above about SMVA rating, i t is better t o provide a more definite means o f absorbing the energy without incurring damage. Connecting a 'field discharge resistor' i n parallel with the rotor winding before opening the field circuit breaker will achieve this objective. The resistor, which may have a resistance value of approximately five times the rotor winding resistance, is connected by an auxiliary contact on the field circuit breaker. The breaker duty is thereby reduced to that of opening a circuit with a low L/R ratio. After the breaker has opened, the field current flows through the discharge resistance and dies down harmlessly. The use of a fairly high value o f discharge resistance reduces the field time constant t o an acceptably low value, though i t may still be more than onc second. Alternatively. generators fitted with static excitation systems may temporarily invert the applied field voltage to reduce excitation current rapidly to zero before the excitation system is tripped.

7.1 6 LcjsS i l F [_X::[';p,TigN

?g:)';Ei;;iQx.i

Loss of excitation may occur for a variety of reasons. i f . : the generator was initially operating a t only 20%-3(&,, o f rated power, it may settle t o run super-synchronously I as an induction generator, at a low level of slip. I n doing !: so, it will draw reactive current from the power system . ' 3,s for rotor excitation. This form of response is particularlv ~ 2 z i . .'(:I., true of salient pole generators. In these circumstances, ;$ ti: 6:. the generator may be able to run for several minute- .<%without requiring to be tripped. There may be sufficient time for remedial action to restore the excitation, but the '-:%. reactive power demand o f the machine during the failure may severely depress the power system voltage t o an {.$ unacceptable level. For operation at high initial power output, the rotor speed may rise t o approximately 105% :$; of rated speed, where there would be low power output and where a high reactive current of up to 2.0p.u. may ,:$ ..,,., . be drawn from the supply. Rapid .;automatic.'% disconnection is then required t o protect the stator windings from excessive current and t o protect the rotor :-' from damage caused by induced slip frequency currents.

1

$,;:.

&;

-$$ 3:

'4:

.::*. The protection used varies according to the s.ize of .i.2: .;.,. generator being protected. .... . -. -+S+:. r! % ;-.

.:.-v On the smaller machines, protection again&.% ;$ asynchronous running has tended t o be optional, but it$$ may now be available by default, where the functionality iz ,is available within a modern numerical generator.:;d! protection package. I f fitted, it is arranged either to.:ii provide an alarm or t o trip the generator. If the generator field current can be measured, a relay element ;!; can be arranged t o operate when this drops below a preset value. However, depending on the generator design and slze relative to the system, it may well be that the machine would be required to operate synchronously with little or no excitation under certain systemconditions.

.?

-:

_

The field undercurrent relay must have a setting below the minimum exciting current, which may be 8% of that. corresponding to the MCR of the machine. Time delay relays are used t o stabilise the protection againsti maloperation in response t o transient conditions and to!. ensure that field current fluctuations due to pole slipping do not cause the protection to reset. I f the generator field current is not measurable. then the technique detailed in the following section is utilised.

For generators above about SMVA rating, protection against loss of excitation and pole slipping conditions is normally applied.

Consider a generator connected to network, as shown i n Figure 17.20. On loss of excitation, the terminal voltage will begin to decrease and the stator current will increase, resulting in a decrease of impedance viewed frEm the generator terminals and also a change i n power factor.

The general case can be represented by a system of circles with centres on the line CD; see Figure 17.21. Also shown is a typical machine terminal impedance locus during loss of excitation conditions.

field

I

!.

A relay to detect loss of synchronism can be located at point A. It can be shown that the impedance presented to the relay under loss of synchronism conditions (phase swingi~gor pole slipping) is given by:

!_. .

O

=

The special cases of EG=Esand EG=O result in a straight-line locus that is the right-angled bisector of CD, and in a circular locus that is shrunk t o point C, respectively. When excitation is removed from a generator operating synchronously the flux dies away slowly, during which period the ratio of is decreasing, and the rotor angle of the machine is increasing. The operating condition plotted on an impedance diagram therefore travels along a locus that crosses the power swing circles. At the same time, it progresses in the direction of increasing rotor angle. After passing the anti-phase position, the locus bends round as the internal e m f . collapses, condensing on an impedance value equal to the machine reactance. 'The locus is illustrated in Figure 17.21.

a r=

17.

'The relay location is displaced from point C by the . : ,... . .. .'. . generator reactanceXG. One problem in determining the position of these loci relative to the relay location is that ..';..;j::i.i>: the value of machine impedance varies with the rate of :,:7:$,$$:i:G.:...... .-.., . slip. At zero slip XG is equal to Xd, the synchronous ;>!:$@&?$$;I:~ -..
n i ~ g l cby 11~11icll E(; 1cc~tl.cli,

If the generator and system voltages are equal, thcabove expression becomes:

7;-:Fi$y

- (x, + x , 4 - ~ , ) ( 1 - , c o l O

2)

.,

i ' 9 9

'

.

:;-.

-,..I..& -. ... . .,.. .. .,..,.>? :;:s+<,:.,:&';;>:~: ,L>%...+ .,..-.i..!:.-

............. .,;.;. .$;:f, 5;;;"..<-..:.: ;,;:.;tg,.., ........ .. ,.:,?.,';*.,:.':.-'."... .. .. . ..,?....<,,, . ;?.,.

+*

C

,-

.:ca51:~,:.

I'

t

1s. f :'

;i

low, perhaps 146, so that for the purpose o f assessing the power swing locus it is sufficient to take the value

XG=2Xd.

'

This consideration has assumed a single value for XG. However, the reacranceXq on the quadrature axis differs from the direct-axis value. the ratio of Xd/Xgbeing known as the saliency factor. This factor varies with the slip speed. The effect of this factor during asynchronous operation is to cause XG to vary at slip speed. In consequence, the loss of excitation impedance locus does not settle at a single point, but it continues to describe a small orbit about a mean point.-

ti

A

I 1

!

j

A protection scheme for loss of excitation must operate

L..

decisively for this condition, but its characteristic must not inhibit stable operation of the generator. One limit o f operation corresponds to the maximum cracticable rotor angle, taken to be a t 120'. The locus of operation can be represented as a circle on the impedance plane. as shown in Figure 17.22. stable operation conditions lying outside the circle.

=t

I .

0

t..

;.::

1:

-3

k;r.

p

u

>.:

-

gI

S

Y-.

;

i: g-..

-

g:,, 5,: $<..

t<<

...

... ..

.

I

.

..

_ ._!. . . . ..

.... . - ,. .

,

figvrc ;7.2;:

.o.::,

LC'.,;,

,;,!,>:!',I;,,!,<

' '

,

c>c!,v:!th! s,.,:cc.,;,:<>"> ,?,:;

I

.,< .

:

.

.*. ....

.

,

.. <

.

.i.\

.

...

.

.,>,.,<:.. . -.

!

On the~samediagram the full load impedance locus for one per unit power can be drawn. Part of this circle represents a condition that is not feasible, but the point of intersection with the maximum rotor anqlc curve can be taken as a limiting operating condition for setting impedance-based loss o f excitation protection.

..:... .

...

5$-i,*.': c~.:.~ ..

*";:; $$% ;<:.?A:

ig+ ;

&.

v=: p+ ,,

-.

Q.

kip;

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:$n .9

rw:=-. .. *+ rgfy $$*$>:.

.

1,;. -: [;.I;

: ,q. ,

.; !-\. - : .. ..

-

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. .

;

:. . ... ' '.. ..:

Figure 17.21 alludes t o the possibility that a protection

. - -....- -.. - --

.

.

Normal machinc opcraring impcdancc

Locus of conyant MVA

+jA'

IC

.

scheme for loss o f excitation could be based on impedance measurement The impedance characteristic must be appropriately set or shaped to ensure decisive operation for loss of excitation whilst permitting stable generator operation within allowable limits. One or two offset mho under impedance elements (see Chapter. 11 for the principles of operation) are ideally suited for providing loss of excitation protection as long as a generator operating a t low power output (20-30%Pn) does not settle down to operate as an induction generator.The characteristics o f a typical two-stage loss of excitation piotection scheme are illustrated i n Figure 17.23. The first stage, consisting of settings X,, and Xbl can be applied to provide detection of loss of excitation even where a generator initially operating at low power might settle dowv to operate as an output (20-30%P,] induction generator.

... .

-

- ---- .-

-+

Pick-up and drop-off time delays t d l and tdo, are associated with this impedance element. Timer t d , is used to prevent operation during stable power swings that may cause the impedance locus o f the generator to transiently enter the locus of operation set by Xbr However, the value must short enough to prevent damage as a result of loss of excitation occurring. If pole-slipping protection is not required (see Section 17.17.2). timer tdo, can be set to give instantaneous reset. The second field failure element, comprising and associated timcrs IdI and tdo2can settings X b l , be used to give instantaneous tripping follovring loss of excitation under full load conditions.

1 /.I

ti.:?

~ : O : C f ' ~ ~ 2 : 1S~l:!r,v:

The typical setting values for the two elements vary according to the excitation system and operating regimf of the generator concerned, since :hew affect th( generator impedance seen by the relay under normal an1 abnormal conditions. For a generator that is neve

ii0-315

17/06/02

l0:re

page 301

-

*crated at leading power factor, or at load angles i n e s s of 90" the typical settings are:

.! 7:!?.1

impedance element diameter Xbl = Xd impedance element offset X,! = -0.5% .

time delay on pick-up, t d r = 0.5s .- 10s time delay on drop.-off, tdo, =

02.

lf a fast excitation system is employed. allowing load of up to 120" to be used, the impedance diameter must be reduced to take account of the reduced generator impedance seen under such conditions. The offset also needs revising. In these circumstances, typical settings would be: pedance element diameter Xb, = 0.5Xd impedance element offset X, time delay on pick-up,

fdl

=

-0.75X;

= 0.5s - 10s

time delay on drop-off, tdol = 0s

fietypical impedancesettings for the second element, if impedance element diameter xb2 =

Protectio:~usinq Rc-VC~SC Pov:r: Eic!-ynt

During pole-slipping, there will be periods where the direction of active power flow will be i n the reverse direction, so a reverse power relay element can be used tn detect this, i f not used for other purposes. However, since the reverse power conditions are cyclical, the element will reset during the forward power part of the cycle unless either a very short pick-up time delay andlor a ,,itabledrop-off time delay is used to eliminate resetting.

,

The main advantage of this method is that a reverse power element is often already present, so no additional relay elements are required. The main disadvantages are the time taken for tripping and the inability to control the system angle at which the generator breaker trip command would be issued, if i t is a requirement to limit the breaker current interruption duty. There is also the difficulty of determining suitable settings. Determination of settings in the field, from a deliberate . pole-slipping test is not possible and analytical studies may not discover all conditions under which poleslipping will occur.

. : ~ . ~ < ~ ~ 2 . . ~ . y ; . . .

:...,jj.?$.:.:"<.;"'.'

' j '.:+!(:.

, ,

% :,!

E L

% .r 2

h

. . . . .

kV -

;

:. : ,-,.!-!.,~~,~:::.,.;:? k ;:..,.:i

;:i.)

;,;;?c8,.:

;,y!t:c:;k.,.:,

...

- . Q

MVA

<:..;.>.-,.,...a,.......... . .

Protection can be provided using several methods. The choice of method will depend on the probability of pole occurring and on the consequences should it

.. .

. . . .

.

With reference to Figure 17.21. a !ass of excitation und& impedanke characteristic may also be capable - o f detecting loss of-synchronism, in applications where the electrical centre of the power system and the generator lies 'behind' the relaying point This would typically be the case for a relatively small generator that is connected to a power transmission system (XG >> (XT + Xsll- With reference to Figure 17.23; i f pole-slipping protection response is required. the drop-off timer tdorof the larger d ~ ~ m e t eimpedance r measuring element should be set to prevent its reset of in each slip cycle, until the rdl trip time delay has expired.

The time delay settings i d 2 and tdO2 are Set to zero to give instantaneous operation and reset.

A generator may pole-slip, or fall out of synchronism with the power system for a number of reasons. The principal causes are prolonged clearance of a heavy fault on the power system, when the generator is operating at a high load angle close to the stability limit, or partial or Complete loss of excitation. Weak transmission links between the generator 2nd the bulk of the Power system aggravate the situation. I t can also occur with embedded generators running in parallel with a strong Utility network if the time for a fault clearancean the slow. perhaps because only lDMT relays are provided. Pole slipping is characterised by large and rapid oscillations in active and reactive power. Rapid of the generator the network is required to ensure that damage to the generator is avoidedand that loads supplied the are affected for very long.

.

-.

it. +.. . - . =.-* r : 2.:. .

. .

,.

::

-

-. .

&.

. pi

-

:

,

.-

1

:+

CY

I

fs

r=

2 2

.

2

- 17.

*

with reverse power protection, this would be an elementary form of pole-slipping protection. I t may not be suitable for large machines where rapid tripping is . required during the first slip cycleand where some controlis required for the system angleat which ,the generator circuit breaker trip command is given. Where protection against pole-slipping must be guaranteed, a more sophisticated method of protection should be used. A typical reset timer delay for pole-slipping protection

... .

,

.

might be 0.6~. . F generator ~ ~ transformer units, the .. , '. .... .... . additional impedance infront of the relaying point may . . take the system impedance outside the under impedance ..::.: :~~:~~-.'~=!:;::'::. . ..: ., . _ .. relay characteristic required for loss of excitation ~.~..:~;.-;:~<;:~., . . :.... * +;.:*: protection. Therefore, the acceptability of this pole- . . . .\._.!:. ... . . :. -,.... -7. slipping protection scheme will be dependent on the . . application. A=-..,..,.:: >.;: . .. . . ,.. .. . . . .-'...i ........ .* ..: ? .: -:'.".:.: '.

'

,

.'

JOI '

:y;::r; .:" ......... ........

'-.5<:e(<:

.:

....

..-?,+

,: . .1. .::; . .. ;,.. ......,. ... -..::.: ....y8.s. . ." ~,':::~.:,~:,~~:.'.

:,.

% ..

'

,

_ _ -. .. .

. .

A more sophisticated approach is tb measure the impedance of the generator and use a lenticular impedance characteristic to determine i f a pole-slipping condition e~ists.The lenticular characteristic is shown i n Figure 17.25. The characteristic is divided into two haives by a straight line, called the blinder.

Large generator-transformer units directly connected to grid systems often require a dedicated pole-slipping protection .scheme to ensure rapid tripping and with system angle control. Historically, dedicated protection schemes have usually been based on a n ohm-type impedance measurement characteristic.

. 4

U

3 P

-

+

,. 6

D

5 -

The inclination, 6, of the lens and blinder is determined.by the angle of the total system impedance. The impedance ;:: of the system and generator-transformer determines the .:.. forward reach of the lens, ZA,and the transient reactance i : o f the generator determines the reverse reach ZB.

Although a mho type element for detecting the change i n impedance during pole-slipping can be used in some applications, b u t with performance limits, a straight line ohm characteristic is more suitable. The protection principle is that o f detecting the passage of the generator impedance through a zone defined by two such impedance characteristics, as shown in Figure 17.24. The characteristic is divided into three zones, A, B, and C. Normal operation o f the generator lies i n zone A. When a pole-slip occurs. the impedance traverses zones B and C, and tripping occurs when the impedance characteristic enters zone C.

tz

.

+j.Y

L

*

Ohm relay 1

Tripping only occurs i f all zones are traversed sequentially. Power system faults should result i n the zones not being fully traversed so that tripping will not be initiated. The security of this type of protection scheme is normally enhanced by the addition of a plain under impedance control element (circle about the origin of the impedance diagram) that isset t o prevent tripping

........ .* .....

a

.,

.

.

. .. . .. . .

.

.

.

.

. . . ....... .

.

.

.

for impedance trajectories for remote power system faults. Setting of the ohm elements is such that they lie parallel t o the total system impedance vector, and enclose it, as shown in Figure 17.24. <

.

.

.

.

.

.

.

;9 A<'

8

-280-315

17/06/02

10:48

Page 303

....

_

...................

windings and t o issue an alarm or trip t o prevent damage. Although current-operated thermal replica protection cannot take i n t o account the effects o f ambient temperature or uneven heat distribution, it is often applied as a back-up .to direct stator temperature measuring devices t o prevent overheating due t o high stator current. With some relays, the thermal replica temperature estimate can be made more accurate through the integration of direct measuring resistance temperature devices. Irrespective of whether current-operated thermal replica protection is applied or not, it is a requirement t o monitor the stator temperature of a large generator i n order t o detect overheating from whatever cause. ..1 c j ~ ~ : ~ :., ; ~ ~ ; c..,-. :.-:>-.:, Tempe~aturesensitive elements, usually of the resistance ... 0 ,:;. type, are embedded i n the stator winding a t hot-spot ..- +& :'3', a, locations envisaged by the manufacturer, the number , .used being sufficient to cover all variations. The - 2 Z elements are connected to a temperature sensing relay L element arranged to provide alarm and trip outputs. The settings will depend on the type o f stator winding S= insulation and on its permitted temperature rise. 2

.:;.%E.$$~:s -N

,$:.2*;ccf7':ii-.--. '-

I f the impedance locus lies above line PP', the swing lles far out i n the power system - i.e. one part o f the power system, including the protected generator. is swinging against the rest of the network Tripping may still occur, but only if swinging is prolonged - meaning that the power system is i n danger of complete break-up Further confidence checks are introduced by requiring t h a t the . ~mpedancelocus spends a minimum tlme withln each zone for the pole-slipping condition t o be valid. The trip signal may also be delayed for a number o f slip cycles even i f a generator pole-slip occurs - thls IS t o both provide confirmation of a pole-slipping condition and allow time for other relays to operate i f the cause of the pole slip lles somewhere In the power system. Should the impedance locus traverse the zones i n any other sequence. trlpping IS blocked.

I

1

1

3. L

Various faults may occur on the mechanical -side o f a generating set. The following sections detail the m i r e important ones from an electrical point of view.

When a generator operating in parallel with others loses its power input, it remains in synchronism with the system and continues to run as a synchronous motor. drawing sufficient power t o drive the prime mover. This condition may not appear to be dangerous and i n some circumstances will not be so. However, there is a danger of further damage being caused. Table 17.1 lists some typical problems that may occur.

-

I Overheating of the stator may result from:

Protection is provided by a low forward powerlreverse power relay, as detailed in Section 17.11

ii. failure o f the cooling system

iv. core faults

:

The speed of a turbo-generator set rises when the steam input is in excess of that required to drive the load at nominal frequency. The speed governor can normally control the speed, and, i n any case, a set running i n parallel with others i n an interconnected system cannot accelerate much independently even i f synchronism is lost. However. i f load is suddenly lost when the HV circuit breaker is trippcd, thc set will begin t o accelerate

Accidental overloading might' occur through the Combination o f full active load current component, governed by the prime mover output and an abnormally high reactive current component, governed by the level

a modern protection relay, it is ielatively simple to Provide a current-operated thermal replica protection element to estimate the thermal state of the stator

*

-

-. ................. JOJ

-

....

.

.

:.- 2

6

-

I : .. f l

I ~hap17-280-315

17/06/02

10: 50

Page 304

rapidly. The speed governor is designed t o prevent a dangerous speed rise even with a 100% load rejection, but nevertheless an additional centrifugal overspeed trip device is provided t o initiate an emergency mechanical shutdown i f the overspeed exceeds 10%. To minimise overspeed on load rejection and hence the mechanical stresses on the rotor, the following sequence . ......... ..:. . .:. .I . is used whenever electrical tripping is not urgently .-.: - required:

..

i. trip prime mover or gradually reduce power input t o zero

ii. allow generated power to decay towards zero

event of loss of vacuum, as this would cause rapid overheating of the low-pressure turbine blades.

GEFJERAioz pr<(jiEn!Q>:

17-20 CO>JP;flE

From the preceding sections, it is obvious protection scheme for a generator has t o take account of - -h many possible faults and plant design variations. :;SEzJ Determination of the types of protection used for a ., particular generator will depend on the nature of the plant and upon economic considerations, which i n turn :;$$$ is affected by set size. Fortunately, modern, multi- ,'-?$ . function, numerical relays are sufficiently versatile to include all of the commonly required protection functions i n a single package,. thus simplifying the .{.$$ decisions to be made. The following sections provide illustrations of typical'protection schemes for generators ,:j.$$: .I-&.... 'connected t o a grid network, but not all possibilities are ':$: illustrated, due to the wide variation in generator sizes i$$: and types.

3

;,@{

:$&, >.,-

-7

'gig.

iii. tripgenerator circuitbreaker onlywhen

5;: 0

power is close t o zero*or when t h e power flow starts t o reverse, t o drive the idle turbine -

-N

k --a

P1

*CI

-

E,

? is

.-. vh I

L 0

.

> ..-

A failure of the condenser vacuum i n a steam turbine driven generator results i n heating of the tubes. This then produces strain i n the tubes, anJ a rise i n temperature o f the low-pressure end of the turbine. Vacuum pressure devices initiate progressive unloading of the set and, if eventually necessary, tripping of the . turbine valves followed by the high voltage circuit breaker. The set must not be allowed t o motor i n the

E

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:g

.

. .. . . .

.,

.. . .. . .

.

.

.

. ... : .

.

;

.

:.:

.... .. ..-" .zc.,

I.

A typical protection scheme for a direct-connected :;'$;> generator is shown i n Figure 17.27. It comprises the:::@ .,: =:e following protection functions: . - .~ :.::..-;.g ... . .: : *Z . .:__: . =rv . . . . . . . -:>;.

G

5 , .

-

3 L

Elcctr~caltrlp of govcmor

.

L

w

/

Emcrgcncv push b u ~ o n E)

II: Q.,

C

J

-

L

P

P

Stator diffcrcntial (biascdlhigh

Iv

'3 P

Stator

E/F (or ncutral voltagc

Back-up ovcrcurrcnt lor voltagc dcpcndcnt OICI

1

1 Loss - 0 Stator winding tcmpcraturc

Excitation

P

Unbalanced loading Undcrlovcrvoltagc

circult brcakcr Low powcr ~nlcrlock

Gcncrator

p -

(

Mechanical fatrlts ( n o n - u r g c n t l ~

N.8. Alarms and I ~ m cdclays arnittcd for simplicity

brcakcr circuit

i7-280-315

17/06/02

Page 3 0 5

10:50

1. stator differential protection

2. overcurrent protection dependent

-

conventional or voltage

3. stator earth fault protection

4. over;o!:agc

instantaneous electrical trip and which can be time delayed until electrical power has been reduced t o a low value. The faults that require tripping o f the prime mover as well as the generator circuit breaker are also shown.

protection

5. undervoltage protection 6. overloadllow forward power1 reverse.-power protection (according t o prime mover type)

7. unbalanced loading 8. overheating 9. pole slipping 10. loss of excitation

'11. underfrequency 12. inadyertent energisation 13. overfluxing 14. mechanical faults

These units are generally of higher output than directconnected generators, and hence more comprehensive protection is warranted. In addition, the generator transformer also requires protection,. for which the protection detailed in Chapter 16 is appropriate Overall biased generatorlgenerator transformer differential protection is commonly applied i n addition, or instead of, differential protection for the transformer alone. A single protection relay may incorporate all of the required functions, or tbe protection o f the transformer (including overall generatorlgenerator transformer differential protection) may utilise a separate relay.

. .

.

.

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.

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frequency and voltage, or for other reasons. From a Utility standpoint, the connection o f e generation may cause problems w i t h voltage co increased fault levels. The settings f o r protecti in :he vicinity cf the ;!ant may require adjustment-with the emergence of embedded generation. It must also be ensured that the safety, security and quality o f supply of the Utility distribution system is n o t compromised. The i embedded generation must n o t be permitted t o supply .' any Utility customers i n isolation, since the Utility supply is normally the means of regulating the system voltage'; and frequency within the permitted limits. It aiso ; normally provides the only system earth connection(s], to :. ensure the correct performance o f system protection in response to earth faults: If the Utility power infeed fails, it is also important t o disconnect the embedded generation before there is any risk of the Utility power': supply returning on t o unsynchronised machines. In, practice this generally requires the following protection functions t o be applied a t the 'Point o f Common 'j Coupling' (PCC) t o t r i p the coupling circuit breaker:

In recent years, through de-regulation o f the electricity supply industry and t h e ensuing commercial competition, many electricity users connected to MV power distribution systems have installed generating st% to operate i n parallel with the public supply. The intention is either t o utilise sur.?lus energy from other sources, or t o usewaste heat or steam from the prime mover for other purposes. * Parallel connection o f generators t o distribution systems did occur before deregulation, but only where there was a net power import from the Utility. Power export t o Utility distribution systems was a relatively new aspect. Since generation o f this type can now be located within a Utility distribution system, as opposed t o being centrally dispatched generation connected t o a transmission system, the term 'Embedded Generation' is often applied.- Figure 17.2 illustrates such an arrangement. Depending on size, the embedded generator(s) may be synchronous or asynchronous types, and they may be connected a t any voltage appropriate to the size o f plant being considered. The impact o f connecting generation t o a Utility distribution system that was originally engineered only for downward power distribution must be considered, particularly i n the area of protection requirements. I n this respect, it is not important whether the embedded generator is normally capable of export t o the Utility distribution system or not. since there may exist fault conditions when this occurs irrespective o f the design intent.

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a. overvoltage

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Limits may be placed by the Utility on the amount of powerlreactive power importlexport. These may demand the use o f an in-plant Power Management System t o control the embedded generation and plant loads accordinqly. Some Utilities may insist on automatic - . tripping o f the interconnecting circuit breakers i f there is a significant departure outside permissible levels of

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b. undervoltage

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e. loss o f ~ t i l i t ~ s .u.:, ~ .~ l ~. .

In addition: 'partichiar ci;cumstances

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may require:$

additional protection functions:

I f plant operation when disconnected from the Utility supply is required, underfrequency protection (Section 17.4.2) will become an important feature of the in-plant power system. During isolated operation, it may be relatively easy to overload the available generation, such that some form of load management system may be required. Similarly, when running i n parallel with the Utility, consideration needs t o be given t o the mode of generator operation if reactive power import is to be controlled. The impact on the control scheme of a sudden break in the Utility connection t o the plant main busbar also requires analysis. Where the in-plant generation is run using constant power factor or constant reactive power control. automatic reversion t o voltage control when the Utility connection is lost is essential t o prevent plant loads being subjected to a voltage outside acceptable limits. ....

3.. :if ,:-> .:!4

,:, '3

f. neutral voltage displacement g. reverse power h. directional overcurrent I n practice, it can be difficult t o meet the protection settings or performance demanded by the Utility without a high risk o f nuisance tripping caused by lack of COordination w i t h normal power system faults and disturbances that do not necessitate tripping o f the embedded generation. This is especially true when applying protection specifically to detect loss of the Utility supply (also called 'loss of mains') to cater for operating conditions where there would be no immediate excursion i n voltage or frequency to cause operation o f conventional protection functions.

> I . : / : , I P ! o i r c ~ i o nI'.,(;;~inst Los5 ::I Il:ili.:v Sv;)~!y

.

If the normal power infeed to a distribution system, o r t a the part of it containing embedded generation is lost, the effects may be as follows: a. embedded generation may be overloaded, leadin! t o generator undervoltage/underfrequency

-315

17/06/02

10:50

Page 307

embedded generation.may bc underloadcd, leading to ove~oltage/overfrequency -

17.27.2

ROCOF

Ee;ay Description

A ROCOF relay detects the rate o f change of frequency i n excess of a defined setpoint. The signal is obtained from a voltage transformer connected close t o the Point of Common Coupling (PCC). The principal method used is to measure the time period between successive zerocrossings to determine the average frequency for each half-cycle and hence the rate of change of frequency. The result is usually averaged over a number of cycles.

little change to the absolute levels of voltage or frequency if there islittle resulting ,-hange to t h e load flow through the PCC rst t w o effects are covered by conventional voltage equency protection. However, if condition (c) conventional protection may not detect the loss ty supply condition or it may be too slow t o do so the shortest possible auto-reclose dead-times

. .

.'

''-'"

ay be applied i n association with Utility overhead otection. Detection of condition (c) must be d if the requirements of the Utility are to be met. ossible methods have been suggested, but the t often used is the Rate of Change of Frequency relay. - I t s application is ba;ed on the fact that of change o f small changes i n absolute , in response to inevitable small load changes, ter with the generation isolated than when the is i n parallel with the public, interconnected tern. However, problems w i t h nuisance tional power system events.

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A voltage vector shift relay detects the drift i n voltage phase angle beyond a defined setpoint as long as it takes place within a set period. Again, the voltage signal is a voltage transformer connected 'loseto the Point o f Common Coupling (PCC). The principal method used is to measure the' time period between successive zero-crossings to determine the duration o f each half-cycle, and then to the durations of earlier half-cycles in the memorised average duration order to determine the phase angle drift.

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following the loss of a large generator.or a . r interconnector, have occurred. ularly true for geographically islanded power h as those of the British Isles. An alternative otection is a technique sometimes referred vector shifts protection. lnthis technique ase ,-hange between the directly mpared with a memorised ax.

sho;ld loss of the Utility supply occur, .it is . - & - , .; c . "nlikely that there will be an exact match between'the 5': o, : - - -... :; . : output o f the. embedded generator(s) and the connected -.?,. o, -.:load. A small frequency change or voltage bhase angle +I -3 change will therefore occur, t o which can be added any changes due t o the small natural variations i n loading o f L an isolated generator with time. Once the rate of change 2 of frequency exceeds the setting of the ROCOF relay for 2 a set time, or once the voltage phase angle drift exceeds the set angle, tripping occurs t o open the connection between the in-plant and Utility networks.

al form of earth fault protection may also be demanded to prevent the backfeed of an earth fault by embedded generation. The.only Way of detecting an fault is use neutral voltage displacement protection. The additional requirement i s only likely t o arise for embedded generation rated above 15OkVA. since the risk of the m a l l embedded generators not being cleared b y other means is negligible.

G

While it is possible to estimate the rate of change of

,

frequency from knowledge o f the generator set inertia and MVA rating, this is not an accurate method for setting a ROCOF relay because the rotational inertia of the complete network being fed by the embedded generation is required. For example, there may be other ~ embedded ~ generators ~ t o, consider. As a result, it is invariably the case that the relay settings are determined at site during commissioning. This is to ensure that the Utility requirements are m e t while reducing the possibility of a spurious trip under the various operating scenarios envisaged. However, i t is very difficult t o . determine whether a given rate of change o f frequency will be due to a 'loss of mainsq incident o r a load/frequeno/ change on the public power network, and hence spurious trips are impossible to eliminate. Thus the provision of Loss of Utility Supply protection t o meet power distribution U t i l i t y interface protection

.17

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d generation are n o t normally s a potential safety hazard. I n the system earth fault, the Utility rate t o remove the Utility power Id also re< in removal of the , through the action o f the ency protection and dependable n. H ~ in view ~ of safety ~ considerations (e.g. fallen overhead line conductors in

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requirements, may actually conflict with the interests o f the national power system operator. With the growing contribution of non-dispatched embedded generation t o the aggregate national power demand, the loss o f the embedded generation following a transmission system incident tnai may aireaiiy ciialleilge the security-of the system can only aggravate the problem. There have been claims that voltage vector shift protection might offer better security. but it will have operation times that vary with the rate o f change of frequency. As a result, depending on the settings used, operation-times might not comply with Utility requirements under all circumstances. Reference 17.1 provides further details of the operation of ROCOF relays and the problems that may be encountered.

Salient details o f the generator, network and protection required are given i n Table 17.2. The example calculations are based on a MiCOM P343 relay in respeq o f setting ranges, etc. . . .,

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The nearest settable value is 3 6 5 4 or 0.731,.

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This protection is applied as remote backup to the downstream overcurrent protection i n the event of protection or breaker failure conditions. This ensures that the generator will not continue to supply the fault under thew conditions.

than the maximum generator load current of 328A. A '1 margin must be allowed for resetting of the relay at this ';j current (reset ratio = 950101 and for the measurement 5 ;~,+: :5~F.k35r..~,~r! ... tolerances of the relay (Solo o f r, under reference :; X; p . ~ . CI Ratio VT Ratio 0.297 50011 : 11000,110 ; conditions), therefore the current setting is calculated as: ,.:

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This section gives examples of the calculations required for generator protection. The first is for a typical small generator installed o n an industrial system that runs in parallel with the Utility supply. The second is for a larger generator-transformer unit connected to a grid system. -

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Biased differential protection involves the determinatio of values for four setting values: I,,. ISz, K I and Kz in :;$ Figure 17.5. I;., can be set a t 5OIoof the generator rating, .@ in accordance with the recommendations for the relay, j:" and similarly the values of I,, 1120010) and K2 (15Wo) of ; generator rating. It remains for the value of K , to be determined. The recommended value is generally @h, :; but this only applies where CT's that conform t o IEC 60044-1 class PX (or the superseded BS 3938 Class X] /j:#$ are used - i.e. CT's specifically designed for use in differential protection schemes. In this application, the CT's are conventional class 5P CT's that meet the relay P , % ' : . requirements in respect of knee-point vcltage, e t c $3 :. .*,. Where neutral tail and terminal CT's can saturate at :!..:-&: different times due to transiently offset magnetising inrush or motor starting current waveforms with an r.m.s. :;(?': level close t o rated current and where there is a high l j R .$& time constant for the offset, the use of a 0% bias so l pe;':& may give rise to maloperation. Such waveforms can k :,$$ encountered when plant o f . similar ..rating t o . the~22~.~$ generator i s being energised or staited: Differen&;yX$ between CT de'sibns'ordiffering remanent fluilevels d":;I% .... lead to asymmetric saturation and the producticin differential spill current. here fore, it .is appropriate t o % : select a non-zero setting for K , , and a value of 5% isy@ ::=. ,.sf ., usual i n these circumstances.

Nevertheless. because such protection is a common requirement of some Utilities, the 'loss o f mains' protyction may have to be provided and the possibility of spurious trips will have t o be accepted in those cases. Site measurements over a period of time of the typical rates of frequency change occurring may assist in negotiations of the settings with the Utility, and with the fine-tuning of the protection that may already be

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The minimum phase-phase voltage for a close-up single- .. phase to earth fault is 57%. so the voltage setting V, must be less than this. A value of 30°10 is typically used, .giving V, = 33V. The current setting multiplying factor.

K must be chosen such that Kls is less than 50%

of the generator steady-state current contribution to an uncleared remote fault. This information is not available

an operation time of not less than 1.13s. At a TMS of 1.0, the generator protection relay operating time will be:

protection such that:

=45.6V L

where:

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Vrfl= eflective voltage setting

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=

dorunstrearn earth-fault current setting

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Hence a setting of 48V is acceptable. Time grading is required, with a minimum operating time of the NVD protection of 1.13s at an earth fault current of 200A Using the expression for the operation time of the NVD t

=

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K/(M-I)sec

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Providing protection for 90% of the winding. V

=

voltage seer1 by relay

Vrnvd = relay setting voltage

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quantities (corresponding t o voltage) is typically used, with '10s t o allow for transients offlrejection, overvoltages on motor starting, etc.

Loss of excitation is detected by a mho impedance relay element, as detailed i n Section 17.16.2. The standard settings for the P340 series relay are: X,= 0 . 5 ~x' (0 ~ ratio/VT ratio)

The second element provides protection in the event of; large overvoltage, by tripping excitation and th; generator circuit breaker (if closed]. This must be set below the maximum stator voltage possible, taking account saturation. As the open circuit the generator is not available, typical values must bec@ ., used. , Saturation will normally limit the maximum"'"" overvoltage on this type of generator to 130%, so a. setting of 120% (132V secondary) is typically used:' Instantaneous operation is required. Generato< manufacturers are normally able t o provide' recommendations for the relay settings. Far embedded ger:erators, the requirements of the local Utility may a1 have to be taken into account. For both elemen&, variety of voltage measurement modes are available t$@ take account of possible VT connections (single or three:@ phase, etc.], and conditions to be protected against I" this example, a thee-phase VT connection is used, aid overvoltages on any phase are t o be detected, so.'? selection of 'Any' is used for this setting.

(in secondary quantities] = -0.5 X 0.297 x 19.36 x 500/100 =

-14.5n

Xb = Xdx (CT r a t i o m ratio)

..

= 2.349fl x 19.36 x (500/100) = 227Q

The nearest settings provided by the relay are X, = 14.552 Xb = 22752. The time delay t d l should be set t c avoid relay element operation on power swings and a' typical setting of 3s is used. This value may need t o be modified i n the light of operating experience. To prevent cyclical pick-up of the relay plement without tripping. such as might occur during pole-slipping conditions, a drop-off time delay td,, is provided and set t o 0.5s. . ,,,.,,..... :.,: :.:+., (<. .,.-%;>..<,;;c G.e:<;>< = < ,, .;:.::s:c ! < .: , ,

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This protection is required t o guard against excessive heating from negative phase sequence currents. whatever the cause. Thegentrator, i s o f salient-poledesign, so from withstand is-8qo of rating IEC '6&34-1;-.the'&ntinuok and the ~ : r w l u e ii:20s. . ~sin<.G~uatTon 17.i, the required relay settingsmn found as f2>>,=0.05 and K = 8.6s. The nearest available values are I,>> = 0.05 and K = 8.6s. The relay also has a cooling time constant K,,,,,that is normally set equal t o the value o f K. To coordinate with clearance o f heavy asymmetric system faults, that might otherwise cause unnecessary operation of this protection, a minimum operation time tmi, should 01 be applied. I t is recommended t o set this to a value of 1. Q Similarly, a maximum time can be applied to ensure that the thermal rating o f the generator is not exceeded (as 17,. ,:, this is uncertain, data not available) and to take account _,,..C .::F&+;i -, of the fact that the P343 characteristic is not identical 6c;$&$$$i with that specified i n .lEC 60034. The recommended .: ,..,".&.k%,~. setting for t,,, is 600s. . !..,. :.~,.'', . . . .'.'.:f.: .. - .. :. .,. <:.;. . . . . . ........... ....,.. ." 7 : ;. ,

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~ h i s ' i siequiied t o protect the generator from s;&i$$$ overloid conditions during periods df op'eration.isii~tdh :.;;qG from the Utility supply. The generating set manufacturer# will normally provide the details o f machine short-tim$$ capabilities. The example relay provides four stages underfrequency protection. In this case, the first stageis! used for alarm purposes and a second stage would b$, ,"$ *i a applied to trip the set.

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The alarm stage might typically be set to 49Hz, w i t h a time delay of 20s, to avoid an alarm being raised unds transient conditions, e.g. during plant motor starting; The trip stage might be set to 48Hz. with a time delay of 0.5s, to avoid tripping for transient, but recoverable, dips in frequency below this value.

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The relay setting i s 5% of rated power.

This is required to guard against various failure modes, e.g. AVR failure, resulting in excessive stator voltage. A two-stage protection is available, the first being a lowset time-delayed stage that should be set to grade with transient overvoltages that can be tolerated following load rejection. The second is a high-set stage used for' instantaneous tripping in the event of an intolerable overvoltage condition arising.

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0.05~5~10~

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500 X 100

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=5W .V.

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This value can be set in the relay. A time deb;; to guard against power swings while genera$i at low power levels, so use a time delay of 5s. NO ..:: timedelay isrequired. 7

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en era tors can normally withstand 105% of rated voltage continuously. SO the low-set stage should be set higher than this value. A sctting of 117.7V in secondary

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,

2

has t o be greater than the fullThe setting current load current o f the generator (6019A). A suitable margin must be allowed for operation a t reduced voltage, so use a multiplying factor of 1.2. The nearest settable value is 72OUA. The factor K is calculated so that the operating current is less than the current for a remote end three phase fault. The steady-state current and voltage a t the generator for a remote-end three-phase fault are given by the expressions:

Q

L

2 2

9)

r: P, C3

- 17-

$>:

d,..

The data for this unit are given i n Table 17.4. It is fitted with t w o main protection systems t o ensure security of $ : ' tripping i n the event of a fault. To econornise on space. I.- . . the setting calculations for only one system, that using a MiCOM P343 relay are given. Settings are given i n P r h a r y quantities throughout. 2.-

ct::;

where:

VN = The settings follow the guidelines previously stated. AS 1OOoIo stator winding earth-fault protection is provided. . ,,.high sensitivity is n o t required and hence J,, can bc set ;::"' to 1O0Io of generator rated current. This equates t o 602A. and the nearest settable value on the relay is M O A I= 0.08 of rated CT current]. The settings for K , . I,, and K, f0ll0w the guidelines i n t h e relay manual. .:<'.

8:

E'' '

,L

Xd

110-load p h n r c - ~ r e u t r a gl o l c r a t o r volrngc

= golerator

d-aris synchronous rcoctance

.

.

'

>,

..

~~:,';;,..-r:.?~:~. .;..,,, ,.-...- .......

,-hap17-280-315

10:50

17/06/02

Paqe

312

A TMS value of 10 is selected, t o match the withstand

hence.

curve supplied by the manufacturer.

IJlr = 2893A =

;;,72,7,6 ':()L?
0.361,y

and

vN.\I?Gf I ' + I x , + ~ ~1') x~ ---f i I ' ~+ I X~~ + X~, + j~2 ~ X ~

VPr=

=J304V

This is provided by a combination of neutral voltage dispiaceiiicnt ai;d :bird h8rmnnic undewoltagc protection. For the neutral voltage displace protection to cover 90% o f the stator winding, minimum voltage allowing for generator operation minimum of 92% o f rated voltage is:

=0.07UN

.u

9,

-4"

--

3 %

h ; I

D

P,

E Q

a %

z

--

.

. . . . .

.'a

-

.

.

2

VJ

17 . . . . . .

.. ... .....

The generator has a maximum steady-state capability of 8010 of rating, and a value o f 1;9 of 10. Settings of I,,,,,, = 0.06 (=480A) and I;, = 10 are therefore used. Minimum and maximum timedelaysof 1s and 1300s are used to co-ordinate with external protectiori and ensure tripping at low levels of negative sequence current are used. .

.

.

.

..,,

. ..

.., ..

Alarm:

<.

...

. .. .

.

- c.......... ..........

:.;,A

,..

The generator-transformer manufacturer supplied the following characteristics: -

. ... . .. , .

Trip:

...... ;

yf

> I .J

v/$ > J . ~ , ~ ~ Ili!i~c , c ~cliaracfc"slic sc

;>:".:....., + .......

,..

.... ;. ; p y<;? ~.? .,.I.s>.;!., .', Hence .+~;i;~

I

:::.

/ ,: i.

:

+,.i'.i.

. .<": .::>,_:. .....I.-, . '.,.?> . . ..' .3, .-.-.'

I :

:-.?..;

.,

i h: .

.>:.

..

,-.<.. .:.Ly+.s

'$$z..:'. .

...

I;6:"' c;:'

:I.

6;:

..,,

.+. v.:

.

'.$.%.'j'.,,. -...a:, ....

.:.c.->.:.. .... ,. .

=956.7V Use a value of 935.3~, nearest setfable value ensures of the iscovered. A 0.5s definih, time delay is used t o prevent spurious trips. The third; harmonic voltage under normal conditions is 20h of rated voltage, giving a value of:

i

....

.....

..

. .. .

.

This protection is a combination of overcurrent with undervoltage, the voltage signa! being obtained from a VT on :he generator side of the system. The current setting used is that of rated generator current of 6019A. in accordance with IEEE C37.102 as the generator-ii for . installation i n the USA. Use 6000A nearest settablevalue. The voltage setting cannot be more than 85% of . the generator rated voltage t o ensure operation does not occur under normal operation. For this application, a value of 50010 of rated voltage is chosen.

0

C

.

A suitable value of V,,,, is 120010 of V':. giving a value of 1565V. The nearest settable value is 3000V, minimum allowable setting. The value of V,,, is required be above the minimum voltage seen by thegenerator for rated a fault. A value 80010 voltage is used for V;,,,. 14400V.

0

-

0.92x18kVxO. 1

A suitable value of K is therefye 0-36x2=0.3

..-.

crrr[,+6:::~ p::r:~:~c-$un

the alarm setting is J8°00xJ.05 = 3 1 5 V / H z . A 0 A time delay of 5s is used to avoid alarms due to transient conditions. The tr,ip setting is J8000xJ-3/6O=360~/1fz .

78kV xO.02

4T

=207.8V .

..

.

The setting- of,..the :.third har protettion-hu;t.be b e l o 6 this-" beingacceptable: use-avslue 6f 166.3V. A tiiiiqde of 0.5s is used. . lnhibiiion o f the e1ement:at.l generator output requires determination dur~n commissioning. ....... ; ;....... / ,

;:,;:>.., :::

;;::;c

(;.<:::<;
The client requires a two-stage loss protection function. The first is alarm only. while th second provides tripping under high load conditions.: achieve this, the first impedance element of the P3 loss of excitation protection can be set i n a c c ~ r d a n . ~ with the guidelines of Section 17.16.3 for a generatok operating at rotor angles up to 120", as follows:

Xbl = O.SXd

=

1.666f2

X a , = 0.75X',j = 0.245R Use nearest settable values of 1.669fl and 0.25 time delay of 5s is used to prevent alarms transient conditions. For the trip stage, settings fo load as given in Section 17.16.3 are used:

k V 2 - 18' Xb,=-------=1.727Q MVA 187.65 Xa,=-0.75X;=-0.

1406R

The nearest settable value for Xb2 is 1.72512. A delay of 0.5s is used.

.

.

Loss of cxcitalion

Alarm: 59.3H2, 0.5s t i m e delay

Voltagc conlrollcd ovcrcurrcnl

1st stage trip: 58.7Hz, 100s time delay

, time delay tage trip: 5 8 . 2 ~ z Is

Alarm: 62Hz, 30s t i m e delay Trip: 63.5Hz, 10s time delay These characteristia can b e set in the relay directly.

The generator manufacturers' recommendation is:

lates i n t o the following relay settings: Alarm: 19800V. 5s t i m e delay Trip: 23400V, 0.1s t i m e delay

d.

Reverse reach. Zn

gh

~ W C ~

'The setting data, according t o the relay

Forward reach, Z,

+ Z,

=

Z,,

=

0.02 + 0.22

=

ZGr,,

=

:er

Rrvcnc P

~ o Slipping ~ c Protcclion

Rcrcnc Powcr

-

... F>2rime dclay

0.652fl

:

Reactance line. Zc = 0.9 x Z =

0 . 9 x 0.22

=

0.138R

.

.

o~cdrcqu~nq

!

Undcrfrcqucnol

!

Z,= gct~rroforr r a ~ ~ s f o n i ~leakage er iri~prdor~ce me

2,

=

rlerluork impcrior~ce ;irrb!r

/'L

N ~ f w . t k P r a r a c r i s a ff A s f . - . r i . m ~

i

i 5 . R*r?

-

~

~ . .

J I J ~

~

.

'

I.,,

i-~~rx powcr

1

I

1.6MW - 0.5s

:.

s sos j,-..-.- --

:

1

Fc2 tirnc dclay <,.:.-

'<

..

F
,

.

0.5s . - :58.7Hz

,

... ,:.::,:-.

lOOs

.

.(

5821ii

'

Is

blrgc ~ C I I C I O I ~ I I , ~ ~ O ; C C : ~ ~C~A U ~ P ! C

:.

.. . ... . . .. . . . ... . .. .:.. . . .<.... . . :,..... :! .. , .I

'

'

': .

.? .7,:'

;.:.;:<';:

i>;:;& -- ,.?;: :*. ..

::.

i&,%:i.-. .. .?. . . . ky$z7L;. .. .:, .,-.... .*- . : ... . .. ... .><;:.,;.

. .,....--. .- -:... !. =.::! .:... j 3 ,x7:.. ,.,.: ., ..> :?,-$; 2.

.

I

G m i l c

:.
,

.

F < 3 limc dclay

I

105

.

PI . DO . tirnc F
where:

PIfunction PI scrling PItimc dclay

.-r

.,..

,.:.cP '.,. ;ks , :% ;' yd i" .:. :: ;< .. ,. .... -.

;:;;.' -,y: -. - .<<.s: . >; .-... . .

:;,~ , , ~ h * " ' ~ ~

-

I

~

,

.

. ..;-. .. . . .,;.... ..L.

.. .

{ ~ h a ~ 1 7 - 2 8 0 - 3 1 5 17/06/02

10:50

Page

314

m

The nearest settable values are 0.2434 0.656Q, and 0.206Q respectively. The lens angle setting; a, is found from the equation:

and, substituting values.

amin = 62.5' Use the minimum settable value of 90". The blinder angle, 8,is estimated to be 80', and requires checking during commissioning. Timers T, and T, are set to l5ms as experience has shown that these settings are satisfactory to detect pole slipping frequenries up to IOtlz.

-

--..c1

This completes the settings required for the generator, and the relay settings are given in Tabte 17.5. Of course, additional protection is required for the generator transformer, according t o the principles described in Chapter 16.

-

*-r

o ;?, U

L

5 E c

C L

2 - .

C

F

5 k

17.1 Survey o f Rote O f Change o f Frequency Relays ond Voltoge Phase Shif? Relays for Loss o f Moins Protection. ERA Report 95-0712R. 1995. ERA

Technology Ltd.

.

ng Criteria

APPS Combined course Generator Protection -Setting Criteria & Tutorials

Page 1 of 45

-

The action required f3llowing response of an electrical or mechanical protectior~.is often catzgorised as follows: . -

I

-

1 . ... ..

I.

..:.<. ,:

:

,. .:i p . ..-. \

:-

. .: :.... ,.

* . ..

.::. ..+'.. ..d... . a.-..;:- ;'.-. .,.... ,, ,.. ~...: .&:'. .< i

..

.

1

Urgent shutdown 7 Non-urgent shutdo.:. 'i Alarm only i

- A n urgent shutdown .:I 3uld .be required, for example, if a phase to phase fault occurred within -vie generator electrical connection. A non-urgent shutdown might be s ~ ~ u e n t i awhere l, the prime mover may be shutdown prior to electr-ically ur, zading the generator, in order to avoid over- spesd. A non-urgent shutdc.-,,n may be initiated in the case of continued unbalar~cedloading. n this case, it is desirable that an alarm should b e given before shutdo\/. .- becomes necessary, in order to allow for operator intervention to remed.. -iie situation. For urgent tripping, - may be desirable to electrically niaintain The shutdowr-7 condition :.!ith -latching protection output contacts, which would requir-e manuc resetting. For a non-urgent shutdown, i?rnay be required that ttie oc-zvt contacts are self-reset, so that production of power can be re-stcr-53 as soon as possible. Generator differential protection

winc--,gs,or connection isulalion, can result i ! i severe Failure of stato~. damage to ttie wine'.-3s and stator core. The extent of the dar-riage will depend upon the f::ult current level and the duration of ihe fault. Protection should b e zpplied to limit the degree of damage in order to limit repair costs. For :::.iniary generating plant, high-speed disconnection of the plant from t t i t - ::Jwer sysiem niay be necessary to niaintain sysieni

-

--

-

OALSTOM Limited, Eries-gy ~ u t o m a t i o n& Inforniation

--

-


-

Page 3 bf 45

High impedance differntial protection

I

The high impedance principle is best explained by considering a differential scheme where one CT is saturated for an external fault, as shown in Figure 3. If the relay circuit i s . considered to be a very high impedance, the secondary current produced by the healthy CT will flow through the saturated CT. If 'the magnetising impedance of the saturated CT is considered to be negligible, the maximum voltage across the relay circuit will be equal to the secondary fault current multiplied by the connected impedance , ( R w + R L +~ R.iz~12) The relay can be made stable for this maximum applied voltage by increasing the overall impedance of the relay circuit, such that the resulting current through the relay is less than its current setting. As the impedance of the relay input alone is relatively low, a series connected external resistor is required. The value of this resistor, RST , is calculated by the formula shown in Figure 3. An additional on linear resistor, Metrosil, may be required to limit the peak secondary circuit voltage during internal fault conditions.


.

.

APPS Combined course Criteria & Tutori

-

I

Protected z o n e

I

V o i l a g e a c r o r s relay circuit

..
.. .

j where K .- i .S

Srab:li s i n g r e s i s t o r , R R st

-VS Is

. limits

s p i I:

, .:"!

.:-:md .51fi

curren: t.= l c j r s l u y sertir;g.l

g.4

<;.g

.. .

.;:*:n

- R~

W'here R R = rdq burden

-. *

.!* . ... ;:

. =.:

..., .:

;

To ensure that the protection will operate quickly during an internal fault the CTs used to operate the protection must have a kneepoint voltage of at least 4Vs. 42:; "7%'.

.Is?

Setting guidelines for high impedance differential protection

:g,

.... .p, .

..G ,C:

..

..I*!

;:%$.

$.-

I:.

,

5r.

.

The differential current setting, should be set to a low setting to protect as much of the machine winding as possible. A setting of 5-10 % of rated-$$ current of the machine is generally considered to be adequate. ,;i& setting may need to be increased where low accuracy class CTs are used ;;.: to supply the protection. A check should be made to ensure that t h e.:$ , primary operating current of the element is less than the minimum fault& cyrrent for which the protection should operate. ,q

his'%

#

3


1

% :

&;


Page 5 of 45

The primary operating current (lop) will be a function of the current transformer ratio, the relay operating current , the number o f current transformers is parallel with a relay element (n) and the magnetising current of each current transformer (le) at the stability voltage(Vs). This relationship can be expressed in three ways: To determine the maxim~~m current transformer mgnetising current to achieve a specific primary operating current with a particular relay operating current.

I.

.

le < 1 /n (lop/CT ratio - I diff)

11.

To determine the maximum relay current setting to achieve a specific primary operating current with a given current transformer magnetising current. Idiff

... 111.

< ( Iop/CT ratio

-

nle )

To express the protection primary operating current for a particular relay operaling current and with a particular level of magnetising current. ,,I

= (CT ratio) x (

ldiil

+ nle)

In order to achieve the required primary operating current with the current transformers that are used, a current setting (I diff) must be selected for the high impedance element, as detailed in expression(ii) above. The setting of the stabilising resistor (RST) must be calculated in the following manner, where the setting is a function of the required stability voltage setting (Vs) and the relay current setting (I diff). RST =

Vs (I diff)

Note: the above fo;mula assumes negligible relay burden. OALSTOM Limited, Energy Automation & Informalion

,' 4

APPS Carnbinecf course

-

Generator Protection -Setting Criteria & Tutorials Page 6 of 45

'

Metrosils are used to limit the peak voltage developed by the current transformers under internal fault conditions, to a value below the insulation level of the current transformers, relay and interconnecting leads, which are normally able to withstand 3000V peak. The following forn~ulaeshould be used to estimate the peak transienl voltage that could be produced for an internal fault. The peak voltage produced during an internal fault will be a function of the current transformer kneepoint voltage and the prospective voltage that would be produced for an internal fault if current transformer saturation did not occur. This prospective voltage will be a function of maximum internal . -..< ..: . . fault secondary current, the current transformer -ratio, . . t h e .current::$ transformer led resistance to the common point; the relay lead resistonc&-"j . . . . and the stabilising resistor value. . ..

:

Vp = 2

< 2 Vk

(Vf

-

Vk)

Where Vp = peak voltage developed by the CT under internal fault condiiiol-1s. Vk = current transformer knee-point voltage Vr = Maximum voltage that would be produced if CT saturation did not

occur.

Setting guidelines for Stator earth fault protection function (51 N) Current operated from a CT in the neutral earth path. ,


-- ----

1

',.:


?. f3

!+-:.

Page 7 of 45

Two independent tripping stages. First stage tripping can incorporate either a definite time or standard inverse type IDMT delay Second stage tripping can be instantaneous or definite time delayed. . Immune to third harmonics.

.-

Applied to directly connected generators.

The protection must be time graded with other earth fault protection. The setting employed should be less than 33% of the earth fault level. A setting of 5% of the earth fault level should be applied for applications

where the differential protection provides less than 95% coverage of the stator winding. Applied to in-directly connected generators. (with the generator earthed via a distribution transformer)

Can be supplied from a CT in either the primary or secondary circuit of the distribution transformer. With a CT in the primary circuit, th.e protection has the advantage of being able to detect an earth fault which causes flashover of the primary winding of the distribution transformer. With the CT in the secondary circuit the protection has the advantage of detecting a short circuit across the loading resistor. A sensitive 5% setting can be applied to the first tripping stage, a short time delay can be applied to stabilise the protection against small earth currents due to VT failures or earth leakage during HV system faults. The second tripping stage can be utilised as a high set. A 10% setting and instantaneous operation ensures fast clearance of generator earth faults.

In the case of direct generator connection, it is common that only one

generator of a parallel set is earthed at any one time, with the earth connections of other machines left open. If the generating plant can also be run directly in parallel with a medium voltage public supply, it i s a common requirement that all generator earth connections are left open during parallel operation. In such circumstances, the main earth fault -

I

-


APPS Combined course -

P

Generator Protection -Settins Criteria 8 Tutorial

a

g

e

4

-!

protection element (le>) will only be operational for an earthed machine It will provide primary earth fault protection for the associated machine backup earth fault protection for other machines and the rest of th power system and thermal protection for the earthing resistor.

For indirectly connected applications, the time-delayed earth fat protection function may be employed in one of two ways:

1. To measure earth fslult current indirectly, via .a CT in the secondc circuit of a distribution transformer earthing arrangement. -

2. To measure earth fault directly, via a CT in the generator winding ea connection. With the first mode of application, the current operated protecli function (51 N) may be used in conjunction with voltage operat protection function { 5 9 N ) , measuring the distribution transforr, secondary voltage. This is a complementary arrangement, where . voltage operated protection function (59N) is able to operate in event of an open-circuited loading resistor and the current opera protection function (51N) is able to operate in the event of a sh circuited resistor. The second mode of application would be used for cases of di resistive earthing. For distribution transformer earthing, this mode offers advantage of being able to respond to an earth fault condition leads to a flashover of the distribution transformer primary connect Such a primary short circuit would render protection on the secon side of the transformer inoperative and it would also result in a very and damaging primary earth fault current. In either mode of application, the main stator earth fault current oper protection element (le>) should be set to have a primary sensitiv' around 5% of the maximum earth fault current as limited by the ear impedance. Such a setting would provide protection for up to 95% c generator stator windings. The probability of an earth fault occurring lower 5% of the generator windings would be extremely low, due i fact that the winding voltage with respect to earth is low in this regior


APPS Combined course

Generator Protection -Setting Page 9 of 45

The time characteristic and setting of the main current operated protection element (le>) should be set to prevent false sperufion during HV system earth fault clearance, where a transient generator earth connection current may appear as a result o: the inter-winding capacitance of the generator step-up transformer. The protection element should also co-ordinate with operation of generator VT primary -fuses, for a VT primary earth fault, and with VT secondary fuses for a secondary earth fault on a VT that has its primary windings earthed. Depending on the VT fuse characteristics, and on HV system earth fault protection clearance times, a definite time delay anywhere between 0.5s and 3.0s would be appropriate.

In machiqes with complex winding connection arrangements, e.g. some hydrogenerators, the probability of a fault occurring in the stator winding star-end region (first 5% of-the winding) might be higher. For a highly rated, expensive machine, such increased probability may prompt operators to apply 100% stator earth fault protection. A suitable 100%stator earth fault protection scheme can be3pplied in these cases.

100 % Stator Earth Fault Protection

The conventional unit type generator has the neutral earthed through a resistance loaded distribution type transformer. For a single ground fault near the neutral end of the winding , there will be proportionately less voltage available l o drive the current through the ground, resulting in a lower fault current and a lower neutral bus voltage.

8,

i'


Q

- iiealtky Cor,dlt.ion F - Faulty Condition

Figure 4 If an earth fault occurs and remains undetected because o its location ( otherwise the probability of a second fault occurring is much greater. Ttsecond fault may result from insulation deterioration caused by transie overvoltages due to erratic , low current , unstable arcing ut the first fat point. This second fault may yields of larger magnitudes.

. A 100% stator earth fault protection is designed to detect earth fat occuring in the regions of machine windings close to the neutral end works on principle involving monitoring of the neutral side and line si components of the third harmonic voltages produced by the generators. -

--

OALSTOM Limited, Energy Automation & Information -


-

Generator protection -Setting Criteria & Tutorials

Page 11 of 45 AC generators in service produce a certain magnitude of third harmonic voltages in their windings. Under healthy conditions of working the third harmonic voltage developed by the machine is shared between the phase to ground capacitive impedance at the machine terminal and the neutral to ground impedance at the machine neutral. In general, under healthy conditions the line and neutral impedances are fixed. Thus irrespective of the magnitudes of the generated third harmonic V3, the third harmonic voltages at the machine line end VL3 and neutral end VN3 should bear a constant ratio.

APPS Combined course Generator Protection -Setting Criteria 8 Tutorials

.-

r

i:.

;:,.

r'r g.

F: ic

$!

,

Page 12 of 45-

Referring to figure 4 it may be noted that when fault occurs at a point say F on the machine -winding, the voltage distribution VN3/VL3 undergoes a change from that during healthy running condition. In the extreme case of a fault occuring on the machine neutral , VN3 becomes zero and VL3 becomes equal to V3. Similarly when a fault occurs on the phase terminal VN3 becomes equal to V3. Ffor all other fault positions,and depending on the f a ~ ~resistance, lt VL3 & VN3 magnitudes will vary.

,

p

f!.: . 5:: I..;: : r

:

[rom the figure 5 it is clear that in order to remain stable under healthy conditions the relay should restrain with in the two lines . The slopes of the two lifles namely n11 & m2 can be suitably set to ensure stability and the same will vary from n~achineto machine.

Setting guidelines for Neutral voltage displacement protection function

Voltage operated Single n7easuring element two time delay stages. In~muneto third harmonics.

Applied to directly connected generators.

Supplied from a broken delta VT The voltage setting should be greater than the effective setting of any down-strean?earth fault protection. A time delay sufficient to allow downstream earth fault protection to

operate first should be used. Fast earth fault protection can be enabled when the generator is no1 connected to the rest of the system.

Application to a directly connected generator I


t

.

APPS Combined course Generator Protection -Setting Criteria 8, Tutorials

Page 13 of 45

For .tl-~is mode of application, the neutral voltage displacement protection should be driven from a broken-delta-connected secondary

f a,n,-tin ILII,~

winding of a generator terminal VT that has its primary winding star-point earthed. 'This VT should be made up of three single-phase units or should be a single-phase unit with a 5-limb core. If the VT is not provided with an independent set of secondary windings for broken delta connection, a set of three single-phase interposing VT's should be applied. The interposing VT's should have their primary windings connected in star to the main VT secondary winding terminals and star-point. Their secondary windings should be connected in broken-delta ,;ormat, to drive the neutral voltage displacement protection function. ~lternafively,this protection function could be driven from a single-phase VT connected between the generator winding star-point and earth. The voltage setting of the neutral voltage displacement protection function should be set higher than the effective setting of current operated earth fault protection on any outgoing feeder from the generator bus. The setting should also be higher than the effective setting of the sensitive directional earth fault protection applied to any parallel generator. The effeciive voltage setting of any current operated earth fault proteclion may b e established by multiplying the primary operating current of the protection b y the generator grounding impedance and dividing by one-third of the VT winding ratio, in the case of a broken delta VT arrangement, or by the actual VT winding ratio in the case of a singlephase star-point VT. -

Applied to in-directly connected generators.

Supplied from the secondary winding of a distribution earthing transformer or from a broken delta VT. A sensitive setting can be applied. A short time delay can be applied to stabilise the protection during voltage fluctuations due to VT failures or earth linkage during H V system

faults.

OALSTOM Limited, Energy Automation & 1nf6rmation -

APPS Combined cocrrse

-


Application to an indirectly connected generator

For this type of application, the voltage operated stator earth fault protection function should be driven from the secondary winding of a distribution earthing transformer. In the case of direct resistive.earthing, or of no deliberate earth connection, the protection should be driven from a VT winding. The voltage setting of the protection function should be set to 5% of the voltage that would be applied to the relay in- the event of a solid fault occurring on one of the generator terminals. This would offer approximately 95% coverage of the generator winding. The voltage operated protection function might be used to complement the current operated protection fundion in the case of distribution transformer earthing.

Setting guidelines for Voltage-dependent overcurrent protection function (51 V)

Provides back up protection for uncleared downstream faults. The protection operating mode can be configured to be: a simple overcurrent, a voltage controlled overcurrent or a voltage restrained overcurrent function. In any of the modes of operation, the associated time delay can be either definite time or standard inverse IDMT. -The voltage dependent overcurrent protection must be time graded with down-stream overcurrent protection. Where overcurrent reluys with start contacts are used on outgoing feeders, time grading con be achieved by blocking the opera-tion of the voltage del-~cndent overcurrent protection. In the simple overcurrent mode the system voltage has no effecl on the current setting of the protection. At normal system voltage the current setting should be 5% above ful load current. .. ... r OALSTOM Limited, Energy Automation & Information


Generator Protection -Setting Criteria (L Tutorials Page 15 of 45

When a fault close to the generator will result in a fault current decrement the system vgltage should be monitored to distinguish between normal load current and a system fault. Here either the voltage controlled or the voltage restrained modes of operation should be se1ected.A step change in the current setting is initiated i f the system voltage falls below a selected level.

I1

Applied when t h e generator i s directly c o n n e c t e d to the system.

I

At normal system voltage the current setting should be 5% above full load current.

I

Under low voltage conditions, the current setting should be reduced to less than 50%of the minimum steady state fault current

-

The voltage control threshold should be selected to ensure that a voltage reduction due to a single phase to earth fault will not result in a change of the current setting.

When negative phase sequence protection is also applied, the calculation of the voltage threshold need only consider the effect of a remote three phase fault.

I

The voltage-dependent overcurrent protection function is a three-phase protection function that is driven by the general protection CT inputs and which is intended to provide backup protection for an uncleared phase fault on the generator busbar or on a feeder from the busbar.

In the case of a generator passing h~ghlyreactive current to a fault the level of fault current can fall below the maximum possible machine load current within 0.5s-1.Os unless a fast-acting automatic voltage regulator (AVR) is available. This is because the AVR is able to boost the level of field excitation during a fault. The problem of fault current decrement can be most acute when the excitation supply is derived from a transformer connected to the generator terminals. Where a fault current decrement is t


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Generator Protection -Setting Criteria 8, Tutorials Page 16 of45

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possible, voltage-dependent overcurrent protection provides limedelayed backup protection with adequate sensitivity for a multi-phase busbar or feeder fault, whiist remaining siabie for ;he highest aniicipaieci level of generatar load current. The generator terminal voltage is monitored as a way of being able to distinguish between normal load and system fault conditions.

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In the voltage-controlled protection mode, a step-change in current setting (I> to K.I>) is imposed when the monitored voltage signal drops below an adjustable threshold setting (Vs).

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The under voltage switching threshold setting (Vs) should be selected so that switching does not take place with the minimum possible phase- 1.; phase voltage for single phase to earth fault conditions. For a single phase :'; fault, the minimum possibje phase-phase voltage would be for a close-up :.!; earth fault on a solidly earthed power system, where the voltage could fall iK:: to 57% of the nominal level. The voltage setting should also be set above..,$;. the maximum phase-phase voltagefor anyelement required to operate-:$ for a remote-end feeder fault. If the negative phase sequence thermal::;: protection function is set and enabled, a remote three-phase fault need *:. only be considered when determining the voltage threshold setting (Vs). .:&.*.. .'.

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Reverse power and low forward power protection functions (32R/32L)

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A compensation angle setting is provided to compensate for CT and VT phase errors. A time delay (typically 5s) should be used to prevent operation of the protection during some system fault conditions and power system swings.

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To detect fluctuating reverse power flow, which could result from failure of a reciprocating prime mover, a delay on drop off timer is available, in addition to .the delay on pick up timer.

Low forward power protection.

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Operates when the fom/ard power falls below the set level. Operation can be instanianeous or time delayed. -

Usually interlocked with non-urgent protection to reduce over speeding of the generator following breaker operation for a non-urgent fault.

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~ypicallevels of motoring power and possible motoring damage that could occur for various types of generating plant are given in table below.

Prime mover

Gas Turbines

power Possible damage Risk of fire or explosion Reverse torque on

10-i5% -

Blade and runner cavitation Thermal stress in blades

Steam Turbines

The need for automatic disconnection is arguably less for plant that is continuously supervised, but, in .the event of prime mover failure, the attention of control staff could be diverted by other aspects of the t


A?PS Combined course Generator Protecfioii -Seffing Criteria 8 Tutorials Page 18 of 45

mechanical failure. If motoring damage can occur rapidly, operator action may be too slow to prevent the onset of damage, so there may be a requirement for automatic generator disconnection or for an alarm to be raised. For unattended generation plant, e.g. small hydro schemes that are only periodically supervised, automatic generator disconnection should occur even if immediate prime mover damage would not be envisaged. If automatic disconnection did not occur in such cases, motoring may be possible for hours, with plant damage being gradually inflicted. Automatic disconnection would also prevent an unnecessary power system loss-,

In many cases, prime mover failure can be detected by non-electrical means; e.g. by a steam turbine differential pressure switch or by a hydraulic flow device. If mechanical means of detecting prime mover failure are provided, an electrical measurement method would not be required or would only be used for backup detection. .. - .--."? .*-, : :.

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The reverse power protection function needs to be time-delayed to'.$$ij prevent false tripping or an alarm given during power system swings, following power system disturbances or following synchronisation. In some .$!! applications, the reverse power protection function should be disabled ;$' $ during certain modes of protected machine operation. One example of $@ such a situation is where, during dry seasons, a synchronous machine is de-coupled from its hydraulic prime mover and operated as a .::$j$ synchronous compensator for power system VAR control. . ..!=; :,,.

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APPS Combined course .

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Generotor Protection -Setting Criteria & Tutorials

Page 19 of 45

With any generator, tripping of the generator breaker and excitation system should be accompanied by throttle or valve closure. There is always a risk, however, that the throttle/valves may not close fully and that machine over speed will result when electrical loading is removed. With large high-speed steam turbo-alternator sets, an apparently small over speed could result in machine damage or wreckage, as well as a threat to human safety. Failure of a steam valve to fully close during a shut-down is an obvious risk This over speed risk could be addressed by using duplicate valves in series.

Even where valves, etc., do close fully, there will be some lag in dissipating all the energy within a prime mover, especially in the event of a shutdown from full-load. Some types of plant, are very prone to over speed following rejection of full-load, but have a good over speed tolerance, e.g. slowspeed hydro generators. Large turbo-alternators, with slender,low-inertia rotor designs, do not have a high over speed tolerance and trapped steam in the turbine, downstream of a valve that has just closed, can rapidly lead to over speed. To reduce the risk of over speed damage to such sets, it i s sometimes chosen to interlock non-urgent tripping of the generator breaker and the excitation system with a low forward power check. The delay in electrical tripping, until prime mover energy has been completely absorbed by the power system, may be deemed acceptable for 'non-urgent' protection trips; e.g. stator earth fault protection for an indirectly connected generator. For 'urgent' trips by instantaneous electrical protection, e.g. stator winding current differential protection, any potentially delaying interlock should not be imposed. With the low probab~lity of 'urgent' trips, the risk of over speed and possible consequences must be accepted. With a large generator, even a very small percentage of rated power could quickly accelerate an unloaded machine to a dangerous speed. A typical under power setting requirement would be 0.5% of rated power. The time delay associated with the low forward power protection function (t) could be set to zero. However, some delay is desirable so that permission for a non-urgent electrical trip is not given in the event of power fluctuations arising from sudden steam valvelthrottle closure. A typical time delay for this reason is 2s.


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Generator Protection -Setting Criteria 8 Tutorials Page 20 of 45

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Negative phase sequence thermal protection function (46)

Protects the rotor of a generator from damage resulting from the heating effects of negative phase sequence currents.

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Provides true negative phase sequence thermal protection and a definite time alarm.

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Accurate over a wide system frequency range.

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The trip threshold should be set slightly higher than the constant negative phase sequence current withstand of the generator.

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The protection must be time graded to allow downstream protection to clear an unbalance fault. l

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T o achieve easier grading with. down stream protection, during-:-f clearance of a heavy asymmetric fault, a minimum operating time for the''$ .. negative phase sequence protection can be set. For negative phase sequence currents slightly above setting, a maximum trip time can be set.

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Can provide back up protection for uncleared asymmetric faults.

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Models the cooling characteristic of the generator, following exposure to negative phase sequence currents.

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The alarm element is commonly set to 70% of the trip setting with a time delay well above the time taken to clear any system faults. The alarm element functions directly on the measured level of negative phase sequence current.

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The NPS protection function is provided for applications where a generator (synchronous machine) is particularly susceptible to rotor thermal damage, in the event of the current supplied to the power system becoming - unbalanced. The degree of susceptibility will depend on the generator rotor design (cylindrical or salient construction), methods of

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Page 21 of 45

forced cooling employed and the presence of any ancillary metallic rotor components.

Monitors the generators terminal irr~pedancein order to detect failures in the excitation system. Uses a circular, offset mho, irr~pedancecharacteristic.

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The diameter of the impedance characteristic is based on the direct synchro-nous reactance of the generator. .The offset of the impedance characteristic based on the direct axis transient reactance of the generator.

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An associated definite time delay prevents operation of the protection during stable power swings. Can be interlocked with the under voltage protection element to prevent operation during power swings. A delay on drop off timer-can be used to detect cyclic operation of the field failure protection. This could result during pole slipping.

This protection function measures the impedance at the terminals of a generator that is run in parallel with another source to detect failure of the generator excitation. The current used for single phase impedance measurement is obtained from the 'general protection CT inputs and the voltage is obtained from the main VT inputs. This protection function is provided with an adjustable, offset circular impedance characteristic, see Figure 6 , an adjustable tripping delay timer (t) and an adjustable measuring element reset time delay (tDO).


Figure 6 Complete loss of excitation-may arise as a result of accidental tripping of the excitaiion system, an open circuit or short circuit occurring in l11e excitation DC circuit, flashover of any slip rings or failure of the excilolion power source. A pure open circuit in the excitation system i s unlikely to he long-lasting in view of the high voltage that would be developed crc~oss the open circuit with the machine running and connected to a po\ver system. Such a fault is likely to evolve quickly into a short circuit fauli.

OALSTOM Limited, Energy Automalion & Information

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Generator Protection -Setting Criteria 8 Tutorials Page 23 of 45

Where a generator stabilises at a high level of slip, following excitation failure, the reverse inductive impedance seen at the generator terminals will be highly reactive and will be less than the direct axis synchronous reactance of the machine ( X d ). A typical minimum value for this impedance is twice the direct-axis transient reactance of the generator (2X d ' ) for a level of slip below 1%. Figure 6 shows a typical machine terminal loss-of-field impedance locus, which illustrates the effect of rotor flux decay, leading to gentle pole-slipping and eventual stabilisation as an induction generator with a level of slip of around 1%. To quickly detect a loss-of-field condhion where machine damage may occur, the diameter of the relay field-failure impedance characteristic (Xb) should be set as large as possible without conflicting with the impedance that might be seen under normal stable conditions or during stable power swing conditions. To meet this objective, it is recommended that the diameter of the relay impedance characteristic is set equal to the generator direct-axis synchronous reactance in secondary ohms. The characteristic offset should be set equal to half the direct-axis transient reactance (O.5X d ' ) in secondary ohms.

The above guidelines are suitable for applications where a generator i s operated with a rotor angle of less than 90" and never at a leading power factor. For generators that may be operated at slightly leading power factors and which may be operated with rotor angles up to 1 20°, by virtue of high-speed voltage regulation equipment, the settings would need to be different. The impedance characteristic diameter should be set to 50% of the direct-axis synchronous reactance (O.5X d ) and the offset should be set to 75% of the direct axis transient reactance (0.75X d ' ) . The field failure protection time delay (t) should be set to minimise the risk of operation of the protection function during stable power swings following system disturbances or synchronisation. However, it should be ensured that the time delay is not so long that stator winding or rotor thermal damage will occur. The stator winding should be able to withstand a current of 2.0 p.u. for the order of 15s. It is unlikely that rotor damage would be incurred in much less time than this. It must also be appreciated that it may take some seconds for the impedance seen at the generator terminals to enter the selected characteristic of the protection function. However, a time delay less than 10s would typically be applied. The minimum permissible delay, to avoid potential problems #



Page 24 of 45 of false tripping due to stable power swings with the above impedance settings, would be of the order cf 0.5s. Some operators have traditionally interlocked operation of impedancetype field failure protection with operation of under voltage detection elements in order to allow a low field failure protection time delay without the risk of unwanted tripping for stable power swings. This arrangement may also have been used to prevent field failure protection operation for hydrogenerators that may be run as synchronous compensator's, with the turbine mechanically decoupled. ,

The field failure protection fucction is offered with an adjustable delay on reset of the trip timer (tDO).This lime delay can be set to ovoid delayed tripping that might arise as a result of cyclic operation of the impedance measuring element during the period of pole-slipping following loss of excitation. The delay on reset of the trip timer (tDO) might also be set to allow the field failure protection funclion to be used for detecting pole slipping of the generator when excitalion is not fully lost; e.g. following time-delayed clearance of a nearby power system fault by delayed protection.

Under voltage protection function (27)

Operates when the three phase voltages fall below the common set point. An adjustable timer is available. Can be interlocked with the field failure protection to prevent its operation during stable power swings. Can be used to initiate dead machine protection Can detect failure of the AVR or system faults which have failed to be cleared by other means. Prevents damage to any connected loads which could occur- during operation at less than rated voltage.


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APPS Combined course Generator Protection -Setting Criteria &Tutorials Page 25 of 45

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The pick up level sho~lldbe set to less than the voltage seen for a three phase fault at the remote end of any connected feeder.

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The time delay should be set to allow the appropriate feeder protection to operate first to clear the fault, and. also to prevent operation of the protection during transient voltage dips.

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A dedicated input is provided to block the operation of the under

voltage and under frequency protection during run-up or run-down of the generator. This input can be driven from an auxiliary contact in the circuit breaker.

Under voltage protection can be used to detect abnormal operating conditions or an uncleared power system fault that may not have been detected by other generator protection. - ...:......-. . ',: .

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For an isolated generator, or for an isolated set of generators, especially in the case of standby generating plant, -a prolonged, under voltage . condition could arise for a number of reasons. One reason would be some failure of automatic voltaae reaulation IAVRY eaui~ment.If such a condition persists, automatic generator tripping should be initiated. to prevent -possible damage to system loads. Another reason could be that a fault exists somewhere on the power system that has not been cleared by other means.

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In the case of generators feeding an industrial system, which is normally fed from a public-power supply, system overcurrent protection settings would have to be above maximum levels of system load current with the normal supply available. If the public supply fails, the local generation would be left feeding the entire system. Where the local generation is unable to meet the entire system load, there would be a provision for the automatic shedding of non-essential loads. If a fault subsequently Occurred on the system, the relatively low fault current contribution of the local generation and its decrement with time may result in the system overcurrent protection failing to respond. In this case it would be expected that the generator backup overcurrent should operate.

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Operation of generator overcurrent protection in the above circumsfances can be assisted by employing voltage-dependent protecfion.Wt-,erethere is a parallel set of generators, -and where the fault

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APPS Combined course Generator Protection -Setting Criteria 8 Tutorials Page 26 of 45

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is relatively remote from the generators, even the generator voltagedependent proteciion r i i a y fail to respond to the fault. If the fault is asymmetric, and if the negative phase sequence thermal protection function has been set and enabled, the unbalanced fault current may be sufficient to operate this form of generator protection. The worst situation would be for an uncleared three-phase fault. Although such a fault would be rare, it may be that the only form of protection that would reliably detect the fault would be generator under voltage protection.

In the case of large thermal power plant generators, a prolonged under voltage condition could adversely affect the performance of the auxiliary plant such as boiler-feed pumps and air-blowers. This would ultimately have an effect on the primary plant performance. If such a situation is envisaged, the application of time-delayed under voltage protection to trip the generator might be a consideration. The under voltage protection function threshold (V<) should be set below the steady-state phase-phase voltage 'for a. three-phase fault at the-' remote end of any feeder connected to the generator bus or up to selected locations within an industrial power network. Allowances should be made for the fault curcent contribution of parallel generators, which will tend to keep the generator voltage up. The time setting of the under voltage protection function (t) should be set longer than the time required for backup feeder protection to clear remote-end feeder faults. The delay should preferably be longer than the time required for the generator back-up overcurrent protection function to respond to such a fault. ~ddifionally,the delay should be long enough to prevent unwanted operation of the under voltage protection function for transient voltage dips during clearance of faults further into the power system or by starting of local machines. The required time delay would typically be in excess ol 3s-5s. To prevent tripping of the under voltage protection function followinc normal shutdown of a generator, a normally closed circuit breake auxiliary contact should be used to energise the under voltage inhib logic input.

Over voltage protection function (59)


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APPS Combined course Generator Protection -Setting Criteria 8, Tutorials

Page 27 of 45

* Operates when the three phase voltages are above the common s e t point. t

Two tripping stages, each with an aajustable timer.

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Protects against damage to the generator insulation and that of any connected plant.

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Recommended for rejection.

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hydrogenerators which may suffer from load -

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*Time delayed protection should be set with a pick up voltage of 100120% of the nominal voltage and a time delay ~ufficientto overcome operation during transient over voltages.

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Instantaneous protection with a setting of 130% - 150% of the nominal voltage can be implemented.

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An unsynchronised generator terminal over voltage condition could arise when the generator is running, but not connected to a power system, or where a single generator is running and providing power to an isolated power system. Such an over v ~ l t a g ecould arise in the event of a fault with automatic voltage regulating equipment or if the voltage regulator is set for manual control and an operator error is made. Over voltage protection should be set to prevent possible damage to generator insulation, prolonged over fluxing of the generating plant or damage to isolated power system loads,

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When a generator i s synchronised to a power system with other sources, a synchronised over voltage could only arise i f the generator was lightly loaded and was requiced to supply a high level of power system capacitive charging current. An over voltage condition might also be possible following a system separation, where a generator might experience full-load rejection whilst still being connected to part of the original power system. The automatic voltage regulating equipment should quickly respond to correct the over voltage condition, but over voltage protection is advisable to cater for a possible failure of the voltage 'regulator to correct the situation or for the possibility .of the regulator having been set to manual control. t.


APPS Combined course Gsnerctor Protection -Setting Criteria & Tutorials Page 28 of 45

,

4g The worst case of generating plant over voltage following a system separation, which results in full-load rejection, could be experienced by hydrogenerators. The response time of the speed governing equipment can be so slow that transient over speeding up to 200% of nominal speed could occur. Even with voltage regulator action, such over speeding can result in a transient over voltage as high as 150%. Such a high voltage could result in rapid insulation damage. The time-delayed over voltage protection function threshold (V>) should typically be set to ] 00%-120%of the nominal voltage . The time delay (t>) silould be set to prevent unwanted tripping of the delayed over voltage protection function due to transient over voltages that do not pose a risk to the generating plant; e.g. following load rejection with non-hydro sets. The typical delay to be applied would be 1s-3s.

Under frequency protection function (81 U)

Two under frequency stages each with an independent timer. First stage can be used to initiate load shedding for industrial systems. Time delayed to allow any down stream load shedding equipment to operate first. Second under frequency stage to trip more rapidly. .A dedicated input is provided to block the operation of the under voltage and under frequency protection during run-up or run-down of the generator. This input can be driven from an auxiliary contact in the circuit breaker.

As well as being able to initiate generator tripping, the under frequency protection can also be arranged to initiate local load-shedding, where appropriate. Under frequency operation of a generator will occur when the power system load exceeds the prime mover capability of an isolated of generators. Where the system load exceeds generator or of a group - - I


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the alternator rating, but not the prime mover rating, the alternator could become overloaded without a frequency drop. !t would therefore be important for the alternator manufacturer to provide stator winding temperature measurem-entdevices, to give alarm or to automatically shut down the generator before winding thermal damage results. -

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Power system overloading can arise when a power system becomes split, with load left connected to a set of 'islanded' generators that is in excess of their capacity. Such events should be allowed for by system planners and automatic system load-shedding should be implemented so that the load would rapidly be brought back within the generation capacity. In this case, under frequency operation would be a transient condition; as during power swings. The degree of load shedding would have to take into account the fact that some generating plant, e.g. gas turbine plant, may have a reduced power capability when running below nominal frequency. In the event of under shedding of load, the generators should be provided wit,h backup under frequency protection to shut down the generating plant before plant damage or unprotected system load .damage could' occur.

..

Under frequency running at nominal voltage will result in some over fluxing of a generator, and its associated electrical plant, which needs to b e borne in mind. However, the more critical considerations would b e in relation to blade stresses being incurred with high-speed turbine generators; especially steam-driven sets. When running away from nominal frequency, abnormal blade resonance's can be set up which, if prolonged, could lead to turbine disc component fractures. Such effects can be accumulative and so operation at frequencies away from nominal should be limited as much as possible, to avoid the need for early plant inspections/overhaul. Under frequency running is most difficult to contend with, since there is little action that can be taken at the generating station in the event of load under shedding, other than to shut the generator down.

To prevent under frequency protection tripping following normal shutdown of a generator, a normally closed circuit breaker auxiliary contact should be used to energise the under frequency protection function inhibit logic.

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Over frequency protection function (810) . .

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Should be set abdve the sustainable over frequency level with a time delay sufficient to overcome transient over frequencies following load rejection.

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Over frequency running of a generating set arises only when the mechanical power input to the alternator is in excess of the electrical load and mechanical losses. The most common occurrence of over :I$ .&.$ frequency is after substantial loss of electrical loading. When a rise in ;:;j\ running speed occurs, the governor should quickly respond to reduce the :$ mechanical input power so that normal running speed is quickly regained. ..,:!;, ,:;

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Over frequency protection may be required as a backup protection .@ function to cater for governor or thiottle control failure following l o i s o t . $ - . .- :.+? M.: load or dyring unsynchronised running. :,!*

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Dead machine protection For a multiple source power system, closure of a generator circuit breakel must be controlled either by automatic synchronising equipment, or by manual breaker closing carried out with the aid of synchronising instruments, and supervised by a synchronism check relay. .... .:F 1.p .. ,

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Page 31 of 45

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maintenance tests or testing control systems. The possible damage caused by connecting a dead machine to a live power system, or energlsing a steam turbo-alternator when on turning gear, could be extremely costly if a method of quickly tripping the generator breaker is not provided. If a dead machine is energised from a live power system, rotor currents will be induced and the machine will accelerate as an induction motor. The induced currents in the rotor body and windings would be very high with the machine initially at standstill and could rapidly result in thermal damage unless the machine is designed for direct-on-line run-up as an induction motor (possibly for starting a gas turbine prime m'over). 'The unexpected shaft rotation could also result in rapid mechanical damage if lubrication systems are not running or if a steam turbo-alternator is on turning gear.

A number of

protection functions could. respond to the inadvertent energisation of a dead .machine. The effective machine impedance. during such enegisation would be similar to its sub-transient reactance and so the current drawn from the power system would-be high. So under voltage and overcurrent protection functions could respond to the condition and can be interlocked with manual tripping Jogic to protect the machine against the inadvertent energisation of a dead machine.

OALSTOM Limited, Energy Automation, & Information


Page 32 of 45

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Pole-slipping protection A generator might pole-slip, or fall out-of-step with other power system

sources, in the event of failed or abnormally weak excitation or as a result of delayed system fault clearance; especially when there is a weak (high reactance) transmission link between the generator and the rest of the power system. With large utility base-load generators, the requirement for pole-slipping f protection will be dependent on the transmission system reactance. In the ; case of generators connected to a dense, interconnected system, pole- ;' slipping protection may not be required. In the case of remote generation :! and a weak radial transmission link to the load centre, stability of :': generation may be an issue. Pole-slipping protection is frequently .!;.a -+ requested for relatively small generators running in parallel with strong $# public supplies. This might be where a co-generator runs in parallel with!$$ the distribution system of a public utility, which may be a relatively strong source, but where high-speed protection for distribution system faults is not $ provided. The delayed clearance of system faults may pose a stability$ .$ threat for the co-generation plant. . ...

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The pole slipping relay ZTO has been designed to protect Synchronous generators against the possibility of the machine running in the unstable region of the power angle curve which would result in pole slip.

The relay consists of one directional relay and one blinder relay operating in conjunction with 40-80 mSec timer . Both characteristics look into the source and consequently ignore all condifions of load other than those which produce a reversal of power flow such as would occur with a condition of pole slip or power ;wing exceeding 90 degree.

The timer is incorporated so that the discrimination can be made between a power swing and a pole slip -condition. A trip condition can only occur if the timer has timed out before the fault moves into t h e .

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If the fault never reaches the operate regionof the b1inder:or moves between the directional and blinder char.acteristics in a time less than the timer setting , no operation will occur.

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NUMERICAL EXAMPLE:

Generator Details Terminal voltage Synctironous Reactance Xd Transient Raactance Xd' Sub-Transient Reactance Xd' ' Continuous Negative withstand capability 12' t Length of longest line emanating from the bus Impedance of the line Bus fault MVA

247 MVA 15.75 KV 205 % 23.4 % 17.9 %

2071-5 MVA

Full load current of the machine A ( MVAx 1000/ 1.732~ KV)

Synchronous reactance of the machine Xd ohms (KVxKVx pu Xd / MVA) Transient reactance of the machine Xd' ohms (KVxKVx pu X d ' / MVA) Sub transient reactance of the machine Xd" ohms (KVxKVx pu Xd' ' / MVA) 1 OYdO 5k 1.5 ohms 1.1 1 ohms

Generator line/neutral side CT primary current Generator line/neutral side CT secondary current A CT sec resistance Lead resistance Generator PT primary voltage Generator PT secondary voltage },

9

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Generator Protection -Setting Criteria 6 Tutorials

Page 35 of 45

CT/ PT Ratio CT primary for inter turn protection CT secondary for in-terturn protection CT sec resistance Lead resistance

5000 A 5A 0.75 ohms 1 ohm

Generator Transformer rating Voltage ratio 240115.75 KV Transformer lmpedance Transformer lmpedance in ohms ohms

250 MVA

14%

Generator Differential Protection 87G - CAG 34

Maximum three phase fault current (Full load current/sljb transient reactance) Fault current referred to secondary Voltage developed across the relay circuit Fault current ref to sec ( CT resistance + 2 lead resistance)

93.68 V

Pick-up setting recommended Voltage developed across the relay at pick up (VA burden .of the relay / pick up current) Stabilising resistance value

183.4

(Voltage developed across the relay-Voltage acro'ss rely at pick up/ Pick

Generator Inter-turn Protection 87G1- CAG 34

Maximum three phase fault current O A L ~ ~ OLimited, M Energy Automation & Information

+

25183 A *

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Generator Protection -Setting Criteria 8 Tutorials

Page 36 of 45

(Full load current/sub transient reactance) Fault current referred to secondary Voltage developed across the relay circuit Fault current ref to sec ( CT resistance + 2 lead resistance)

69.25 V

Pick-up setting recommended Voltage developed across the relay at pick up (VA burden of the relay / pick up current)

134.5 Stabilising resistance value ohms (Voltage developed across the relay-Voltage across rely at pick up/ Pick up current)

Generator Field Failure Protection 40G--YTGM15

'

'

..

Diameter setting (0.5 x synchronous recatance)

1.03 ohms

Diameter setting ref to secondary ohms Offset setting of the relay ohms (0.5~ transient reactance) Offset setting of the relay ref- to secondary

1.68 ohms

Timer settings: Pick up timer Drop off timer

OALSTOM Limited, Energy ~utomation& Information

10 Sec

2 Sec

..

Protection-Setting Criteria 8, Tutorials

Page 37 of 45

0.1 6 ohms

0.14 ohms 0.22

3.07 ohms 75 degree 55

.

-

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- .-


Generator Protection -Setting Criteria 8, Tutorials

Page 38 of 45

Generaivr Irr-~pedzjiice Generator transformer impedance Source impedance angle (generally assumed to be 80") Rate of slip ( should be provided by the manufacturer, otherwise assumed to be .I 600 Elec. Deg per second)

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1. Select a suitable scale for the diagram. Draw the X and Y axes with Origin as (0) -

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2. Plot .the Generator impedance along the negative "Y- axis" to get point (G)

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3. Plot the Generator Transformer impedance at positive "Y - axis" to get point (T)

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4 . Draw source imped&nce at an angle of 80° (or source, impedance;::.<$ . .:angle i f available) from point (T) to getpoint (S) . .-..:.,:2_ :...-. . :.-

. :,$< . -.

.

5. Connect points (G) and (S) by a straight line.

;1

6. The locus of Pole slip will be nearer to either (G) or (S) depending on the ratio between emfs at (G) and (S). We assume this ratio to be equal to 1. Thus the pole slip locus is the bisector of line (G)---(S). Mark the point ( 1 ) on the line (G) ---(S) where the Pole slip locus cuts it (centre of the line).

7. With point ( 1 ) as center and (1)---(GIas radius draw a circle. Mark the point where this circle cuts the locus as ( 2 ) . 8. Draw a line passing through the origin (0) at 75". Mark the point v,/here this line cuts the pole slip locus as (3).This is the directional line. 9. Measure the obtuse angle at point (4) between the lines (G)---(4)and (S)---(4). This is named as (4.

1O.The obtuse angle at point (2) should be 270". Name this as (a,).

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APPS C o m b i n e d course' Generator Protection -Setting Criteria 8. Tutorials Page 40 of 45

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Generator Back-up Impedance 21G YTGMl5

lmpedance required to cover the entire line under maximum generation conditions,

1

Where n is the No. of niachines in parallel

secondary

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~ : ~ o w areach rd to be set in relay ohms Reverse reach (25% of forward reach)

= 0.98 ohms

Timer setting

= I sec

Timer setting need to be co-ordinated with Zone 2 Timing

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Negative Sequence Protection 46G- CTNM31

= 5%

Negative seq current 125

122t ( in terms of K1 & K3 )

QALSTOM Limited, Enerqy Automation & Information

= 8


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Criteria & Tutorials

12 Alarm setting -

Alarm timer setting (fixed) Sec

Generator Reverse Power Protection 32G

- WCDM + VTT

Pick-up setting (depends on the type of prime mover) Time delay

= 5 Sec

Generator 95 % Stator Earth Fault Protection 64s - VDGl4

.

.-

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= 5.4 V . .:Q '>

= 1 Sec

Time delay

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Time setting need to be co-ordinated with down stream Earth Fault relays in;'! .-:+ case of Direct connected svstems.

Generator 100 % Stator Earth Fault Protection 64s - PVMM163

The required settings for this 95-100 % protection can be selected only on measurement and studying the machine third harmonic behaviour a1 site.

Measurement of Generator Third Voltaaes - - . - - - - -~ ~ . ~ ~ Harmonic . ..~ ~

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Generator Protection -Setting Criteria 8, Tutorials

Page 43 of 45

a) Measure the filtered third harmonic voltages from neutral side (VN3) and Line side (VL3) at the following TEST SOCKET pins provided on the front of the reiay PVMM. Digital muitimeter in AC millivolts range can be used for this purpose. VN3 - Across 1 & 7 VL3 - Across 2 & 7 b) 'These measurements areto be made during voltage build up of Generator before synchronization and after' synchronizing at different load (MW) and excitation (MVAR j conditions.

Study of Generator Third Harmonic Voltages

The third harmoni; voltages measured above are plotted in a graph with VN3 on X-axis and VL3 on Y-axis. Drawtwo lines enclosing.all,measured values with some tolera-nee. . ~ .. . v ' a l ~ a t e ~ i i o ~ e .and,m2 s ' m l of these lines. The slopes can b e calculbted by ielecting any pointalongthe line-andb y .. computing its V N ~ / \ /ratio; L~ . . .

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.

..

.

.

.

.

.

..

Alternatively, calculate VL3/VN3 from each set of readings under different load conditions. Select the maximum and minimum values of these ratio. Then m l will be maximum VL3/VN3+5%and m2 will be VL3/VN3 - 5%. -

The dead band setting K and the null setting potenliometer "a" can be calculated as given below and set it accordingly in the relay.

b

Example:

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Generator Protection-~eftj,$ Criteria 8, TvtorialSPage 44 o f z

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The following table shows the actual values of the generator VL3 and VN3 obtained from site:

1. Before Synchronization: Vn3(mvolts) Point: 187

V13(mvolts) Poi1

Volta e kV

4 5 6 7 8 9

193.6 324 49 1 658 810 967 -1 1 16 1306 1570 1 680 1730

2 3

!-L

4

-

-

-

-

20.9 - 76.4 1 28 194.5 263 325 390. 452 534 650 698 720

5 6 7 8 9 10 11

2. At different load (MW) conditions

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Active Load(MW)

Reactive

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APPS. Combined course Generafor Profecfion -Setting criteria & Tutorials

Page 45 of 45

0.414 0.415

. -

0.427

.

0.435 0.436

.

0.448

0.393 0.395

0.405

Generator 3rd Harmonics

Vn3(N eutra I Side)

From the table. m 1 = 0.454

1

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..

.

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Generator Protection -Setting Criteria 8, Tutorials Page 46 of 45 -. '

Calculated values are

K = 3.1 and a = 0.409

Dead Machine Protection 6: B

- CTIG+VTUM+VTT

Overcurrent setting 'FLC Under voltage relay setting -

Timer setting

= 1 Sec

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Distance Protection Notes .

.

.

....

1.6.1

Zone 1 Setting

1.6.2

Zone 2 Setting

1.6.3

Zone 3 Setting

1.6.4

Settings for Reverse Reach and Other Zones

1.7.:

Amplitude and Phase Comparison

1.7.2 Plain lmpedance Characteristic 1.7.3

Self-Polarised Mho Relay

1.7.4

Offset MhoJLenticular Characteristics

1.7.4.3

Application of Lenticular Characteristic

1.7.5 Fully Cross-Polarised Mho Characteristic 1.7.6 Partially Cross-Polarised Nlho Characteristic

Protection Against Power Swings - Use of the Ohm Characteristic

1.7.8

1.7.9 Other Characteristics

1.8.1 Starters for Switched Distance Protection

1.9

Effect of Source lmpedance a_nd Earthing Methods 1.9.1 Phase Fault lmpedance Measurement 1.9.2 Earth Fault lmpedance Measurement '

1.10.1 Minimum Voltage at Relay Terminals 1.10.2 Minimum Length of Line 1.10.3 Under- Reach - Effect Of Remote lnfeed 1.10.4 Qver-Reach 1.10.5 Forward Reach Limitations

4.10.6 Power Swing Blocking 1.10.7 Voltage Transf~merSupervision Other Distance Relay Features Distance !?e!ay Application Example 1.12.1 Line Impedance 1.12.2 Residual Compensation 1.12.3 Zone 1 Phase Reach

-

1.12.4 Zone 2 Phase Reach 1.12.5 Zone 3 Phase Reach 1.12.6 Zone Time Delay Settings t Reach Settings 1.12.7 Phase ~ a u lResistive 1.12.8 Earth Fault Impedance Reach Settings 1.12.9 Earth Fault Resistive Reach Settings References

1

Introduction The problem of combining fast fault clearance with selective tripping of plant is a key aim for the protection of power systems. To meet these requirements, high-speed protection systems for transmission and primary distribution circuits that are suitable for use with the automatic reclosure of circuit breakers are under continuous development and are very widely applied. Distance protection, in its basic form, is a non-unit system of protection offering considerable economic and technical advantages. Unlike phase and neutral overcurrent protection, the key advantage of distance protection is that its fault coverage of the protected circuit is virtually independent of source impedance variations. This is illustrated in Figure 1.1, where it can be seen that overcurrent protection cannot be applied satisfactorily. Distance protection is comparatively simple to apply and it can be fast in operation for faults located along most of a protected circuit. It can also provide both primary and remote back-up functions in a single scheme. It can easily be adapted to create a unit pr'otection scheme when applied with a signalling channel. In this form it is eminently suitable for application with high-speed auto-reclosing, for the protection of critical transmission lines.

Relay R, setting >7380fi

I 1SIN

Therefore, for relay operation for line f a u l t s , Relay current setting <6640A a n d >7380A This is impractical, overcurrent r e l a y not s u i t a b l e Must use Distance or U n i t . P r o t e c t i o n

Figure I .1: Advantages of distance over overcurrent protection

I

. . . . . :. . . . . . . .. . . .. . . .. . . . . .

.

.

.

Page 3

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1.2

Principies of Distance Relays

Since the impedance of a transmission line is proportional to its length, for distana measurement it is appropriate to-use a relay capable of measuring the impedance of : line up to a predetermined point (the reach point). Such a relay is described as a distana relay and is designed to operate only for faults occurring between the relay location an( the selected reach point, thus giving discrimination for faults that may occur in differen line sections. The basic principle of distance protection involves the division of the voltage at th relaying point by the measured current. The apparent impedance so calculated compared with a predetermined impedance (normally the impedance of the circuit tieir protected multiplied by some factor), known as. the reach point. If the measurc impedance is less than the reach point impedance, it is assumed that a fault exists on-tt line between the relay and the reach point. The reach point of a relay is the point along the line impedance locus that is intersect by the boundary characteristic of the relay. Since this is dependent on the ratio of volta and current and the phase angle between them, it may be plotted on an RMdiagram. 7 loci of power system impedances as seen by the relay during' faults, 'power swings c load variations may be plotted on the same diagram and in this manner the performar of the relay in the preser,ce of system faults and disturbances may be studied. '

7.3

Relay Performance Distance relay performance is defined in terms of reach accuracy and operating t Reach accuracy is a comparison of the actual ohmic reach of the relay under prac conditions with the relay setting value in ohms. Reach accuracy particularly depend the level of voltage presented to the relay under fault conditions. The imped: measuring techniques employed in particular relay designs also have an impact. Operating times can vary with fault current, with fault position relative to the relay sc and with the point on the voltage wave at which the fault occurs. Depending o measuring techniques employed in a particular relay design, measuring signal t r a ~ errors, such as those produced by Capacitor Voltage Transformers or saturating can also adversely delay relay operation for faults close to the reach point. It is us1 electromechanical and static distance relays to claim both maximum and mir operating times. However, for modern digital or numerical distance relays, the va between these is small over a wide range of system operating conditions an1 positions. 1.3.1 ElectromechanicallStatic Distance Relays

With electromechanical and earlier static relay designs, the magnitude 1 quantities particularly influenced both reach accuracy and operating time customary to present info-mation on relay performance by voltagelreach as shown in Figure 7.2, and operating timelfault position curves for variou of system impedance ratios (S.I.R.'s)as shown in Figure 1.3,where:

Page 4

'

and

.

ZS= system source impedance behind the relay location ZL = line impedance equivalent to relay reach setting

% relay rated v o l t a g e L , Ll

rn

(a)

Phase-earth f a u l t s

% relay rated voltage (b) Phase-phase f a u l t s

(c)

% relay rated voltage Three-phase and three-phase-earth f a u l t s

Figure 1.2: Typical impedance reach accuracy characteristics for Zone I

0

10 20 30 40 50 60 70 80 90 100 Fault position (% relay setting)

(a) With system impedance ratio of I/?

o

ioio3o4b~o6b70ao901bo Fault position (Oh relay setting)

( b ) With system impedance ratio of 3011 Figure 1.3: Typical operation time characteristics for Zone 1 phase-phase faults Alternatively the above information was combined in a family of contour curves, where the fault position expressed as a percentage of the relay setting is plotted against the source to line impedance ratio, as illustrated in Figure 1.4. ........

.

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=. 6

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Zone 1 phase-pnase fault: maximum operation times

Figure 1.4: Typical operation-time contours

e

. . .

1.3.2 DiqitalINumberical Distance Relays

:

DigitalINumerical distance relays tend to have more consistent operating times. They are usually slightly slower than some of the older relay designs when operating under the best conditions, but their maximum operating times are also less under adverse waveform conditions or for boundary fault conditions.

4

Relationship Between Re!ay Voltzge and ZS!ZL Rs;tio A single, generic, equivalent circuit, as sbown in Figure 1.5(a), may represent any fault condition in a three-phase power system. The voltage V applied to the impedance loop is the open circuit voltage of the power system. Point R represents the relay location; iR and VR are the current and voltage measured by the relay, respectively. The impedances Zs and ZLare described as source and line impedances because of their position with respect to the relay location. Source impedance Zs is a measure of the fault level at the relaying point. For faults involving earth it is dependent OP the method of system earthing behind the relaying point. Line impedance ZL is a measure of the impedance of the protected section. The voltage VR applied to the relay is, therefore, For a fault at the reach point, this may be alternatively expressed in terms of source to line impedance ratio Zs/ZL are by means of the following expressions:

VR = IRZL where :

. .

therefore :

V,

=

I

(Zs / Z L )

V +

... Equation 1.I

1

(a) P o w e r s y s t e m configuration

0

. .

0.1

.

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012 0.3

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System ~ m p e d a n c eratio

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8

.

3 4 5

10

zs --

=,

(b) Variation of relay voltage w ~ t hsystem source to line impedance r a

Figure 1.5: Relationship between source to line ratio and relay voltage

The above generic relationship between VR and Z d Z L , illustrated in Figure 1.5(b), i for all types of short circuits provided a few simple rules are observed. These are: For phase faults, V is the phase-phase source voltage and Z d Z L is the positive sec source to line impedance ratio. VR is the phase-phase relay voltage and IR is the phase relay current, for the faulted phases

VR =

I

(Zs / Z L ) + 1

"P -P

... Equation 1.2

i. F o i earth faults, V is the phase-neutral source voltage and Zs/Zl is a composite ratio involving the positive and zero sequence impedances'. V phase-neutral relay voltage and IR is the relay current for the faulted phase

Paoe 8

:

and

Voltaae Limit for Accurate Reach Point Measurement The ability of a distance relay to measure accurately for a reach point fault depends on the minimum voltage at the relay location under this condition being above a declared value. This voltage, which depends on the relay design, can also be quoted in terms of an equivalent maximum ZslZL or S.I.R. Distance relays are designed so that, provided the reach'point voltage criterion is met, any increased mea~uringerrors for faults closer to the relay will not prevent relay operation. Most modern relays are provided with healthy phase voltage polarisation andlor memory voltage polarisation. The prime purpose of the relay polarising voltage is to ensure correct relay directional response for close-up faults, in the f o h a r d or reverse . direction, .where the fault-loop voltage measured by the relay.may be very small. . . . Zones o f Protection Careful selection of the reach settings and tripping times for the various zones of measurement enables correct co-ordination between distance relays on a power system. Basic distance protection will comprise instantaneous directional Zone 1 protection and one or more time-delayed zones. Typical reach and time settings for a 3-zone distance protection are shown in Figure 1.6. Digital and numerical distance relays may have up to five zones, some set to measure in the reverse direction. Typical settings for three forward-looking zones of basic distance protection are given in the following sub-sections. To determine the settings for a particular relay design or for a particular distance teleprotection scheme, involving end-to-end signalling, the relay manufacturer's instructions should be referred to. 1.6.1

zone' 1 Settinq Electromecha~nicallstaticrelays usually have a reach setting of up to 80% of the protected line impedance for instantaneous Zone 1 protection. For digitallnumerical distance relays, settings of up to 85% may be safe. The resulting 15-20% safety margin ensures that there is no risk of the Zone 1 protection overreaching the protected line due to errors in the current and voltage transformers, inaccuracies in line impedance data provided for setting purposes and errors of relay setting and measurement. Otherwise, there would be a loss of discrimination with fast operating protection on the following line section. Zone 2 of the distance protection must cover the remaining 15-20% of the line.

1

Page 9

1.6.2 _Zone2 Setting To ensure full coverage of the line with allowance for the sources of error already listed in the previous section, the reach setting of the Zone 2 protection should be at least 120% of the protected line impedance. In many applications it is common practice to set the Zone 2 reach to be equal to the protected line section +50% of the shortest adjacent line. Where possible, this ensures that the resulting maximum effective Zone 2 reach does n.ot extend beyond i i ~ erniniiiiiii-ii zffective Zone 1 reach of the adjacent line protection. This avoids the need to grade the -Zone 2 time . settings between upstream and downstream relays. In electromechanical and static relays, Zone 2 , protection is provided either by separate elements or by extending the reach of the Zone 1 elements after a time delay that is initiated by a fault detector. In most digital and numerical relays, the Zone 2 elements are implemented in software. Zone 2 tripping must be time-delayed to ensure grading with the primary relayins applied to adjacent circuits that fall within the Zone 2 reach. Thus completc coverage of a line section is obtained, with fast clearance of faults in the first 80 85% of the line and somewhat slower clearance of faults in the remaining sectior of the line.

A- <*

T~mel

Source

Sol

Time) Zone 1 = 80435% of protected line impedance Zone 2 (minimum)= 120% of protected line Zone 2 (maximum) < Protected line + 50% of shortest second line Zone 3F =-I .2 (protected line + longest second line) Zone 3R = 20% of protected line

X = Circuit breaker tripping time Y = Discriminating time

Figure 7.6: Typical time/distance characteristics for three zone distance protection 1.6.3

Remote back-up protection for all faults on adjacent lines can be provided t third zone of protection that is time delayed to discriminate with Zone 2 protec plus circuit breaker trip time for the adjacent line. Zone 3 reach should be set 1 least 1.2 times the impedance presented to the relay for a fault at the remote of the second line section.

i

.. .. _.

:tx;.

Zorie 3 Settinq

Page 10 , A'.

.

.

..

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.

.

.

. ..

.

On interconnected power systems the effect of fault current infeed at the remote busbars will cause the impedance presented to the relay to be much greater than the actual impedance to the fault and this needs to be taken into amount wilen setting Zone 3. In some systems, variations in the remote busbar infeed can prevent the application of remote back-up Zone 3 protection. but on radial distribution systems with single end infeed, no difficulties should arise.

1.6.4 Settinqs for Reverse Reach and Other Zones Modern digital or numerical relays may have additional impedance zones that can be utilised to provide additional protection functions. For example, where the first three zones are set as above, Zone 4 might be used to provide back-up protection for the local busbar, by applying a reverse reach setting of the order of 2.5% of the Zone 1 reach. Alternatively, one of the forward-looking zones (typically zone-3) could be set -with a small reverse offset reach from the origin of the- RIX diagram, in addition to its forward reach setting. An offset impedance measurement characteristic is non-directional. One advantage of a non-directional zone of impedance measurement is that it is able to operate for a close-up, zeroimpedance fault, in situations where there may be no healthy phase voltage signal or memory voltage signal available to allow operation of a directional impedance zone. With the offset-zone time delay bypassed, there can be provision of 'SwitchOn-To-Fault' (SOTF) protection. This is required where there are line voltage transfoimers, to provide fast tripping in the event of accidental line energisation with maintenance earthing clamps left in position. Additional impedance zones may be deployed as part of a distance protection scheme used in conjunction with a teleprotection signalling channel.

&: %:

.

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1.7. Distance Relay characteristics . .

_

.

.

. . .

.

.

.

. .

.

Some numerical relays measure the absolute fault impedanceand t h e n determine whether operation is required according to impedance boundaries defined on the R/X diagram. Traditional distance relays and numerical relays that emulate the impedance elements of traditional relays do not measure absolute impedance. They cornpare the measured fault voltage with a replica voltage derived from the fault current and the zone impedance setting to determine whether then fault is within zone or out-of-zone. Distance relay impedance comparators or algorithms which emulate traditional comparators are classified according to their polar characteristics, the number of signal inputs they have, and the method by which signal comparisons are made. The common types compare either the relative amphtude or phase of two input quantities to obtain operating characteristics that are either straight lines or circles when plotted on an R/X diagram. At each stage of distance relay design evolution the development of impedance operating characteristics shapes and sophistication has been governed by the technology available and the acceptable cost. Since many traditional relays are still in service and since some numerical relays emulate the techniques of the traditional relays, a brief review of impedance comparators is justified. 1.7.1 Amplitude and Phase Comparison Relay measuring elements whose functionality is based on the comparison of two independent quantities are essentially either amplitude or phase comparators. For the impedance elements of a distance relay, the quantities being compared are the voltage and current measured by the relay. There are numerous techniques available for performing the comparison, depending on the technology used. hey vary from balanced-beam (amplitude comparison) and induction cup (phqse comparison) electromagnetic relays, through diode and operational .amplifier

Page 11 .

.

.

.

. .

..

.

. .

.-

..

.:

comparators ir! static-type-distance relays, to digital sequence comparators in digital relays and to algorithms used in numerical relays.

I

Any type of impedance characteristic obtainable with one comparator is also obtainable with the other. The addition and subtraction of the signals for one type j of comparator pioduces the required signals to obtain a similar characteristic using the other type. For example, comparing V and I in an amplitude comparator results ~. in a circular impedance ch3racteistlc-sentred at the ofiglr! of the--=diagram. If the sum and difference of V and I are applied to the phase comparator the result is a similar characteristic. Plain Impedance Characteristic -

This characteristic takes no &ccount of the phase angle between the current an the voltage applied to it; for this reason its impedance characteristic when plotted on an R/X diagram is a circle with its centre at the origin of the co-ordinates and radius equal to its setting in ohms. Operation occurs for all impedance values le than the setting, that is, for all points within the circle. The relay characteris shown in Figure 11.7, is therefore nondirectional, and in this form would oper for all faults along the vector AL and also for all faults behind the busbars up to impedance AM. It is to be noted that A is the relaying point and R A B is the a by which the fault current lags the relay voltage for a fault on the line A 5 and is the equivalent leading angle for a fault on line AC. Vector A 5 represents the impedance in-front of the relay between the relaying point A and the end o AB. Vector A C represents the impedance of line A C behind the relaying point. AL represents the reach of instantaneous Zone 1 protection, set to cover 80% to 85% of the protected line. . .

t

Line GK

Line G H

-

:

I

B

C

-

Figure 1.7: Plain impedance relay characteristic

Page 12

..,

Iirect i I el erne I

(a) C h a r a c t e r i s t i c of c o m b i n e d directional! impedance r e l a y

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(b) Illustration of u s e of directional!impedance circuit diagram

relay:

: ,R , d i s t a n c e element at A R :,, directional element at A ( c ) Logic f o r directional and impedance elements at A Figure 1.8: Combined directional and impedance relays

.-.

y+: .. r F.:.

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Page 13 --

A relay using this characteristic has three important disadvantages:

i.

it is non-directional; it will see faults both in front of and behin point, and therefore requires a directional element to give it discrimination

i.

it has non-uniform fault resistance coverage

iii.

it is susceptible to power swings and heavy loading of a long line, be the large area covered by the impedance .circle

Directional control is an essential discrimination quality for a distance make the relay non-responsive to faults outside the protected line. Thi obtained by the addition of a separate directional control element. The i characteristic of a directional control element is a straight line on the RI so the combined characteristic of the directional and impedance re semi-circle APLQ shown in Figure 1.8. If a fault occurs at F close to C on the parallel line CD, the directio will restrain due to current IF,. At the same time, the impedance unit i from operating by the inhibiting output of unit RD.If this control is not under impedance element could operate prior to circuit breaker C opening. Reversal of current through the relay from IF,to IF2 when C opens could then result in incorrect tripping of the healthy line if the directional unit Ro operat impedance unit resets. This is an example of the need to consider t ordination of multiple relay elements to attain reliable relay perfor evolving fault conditions. ,. In older . relay designs, ,.the.type. of ..p addressed was commonlyiefefred toas orie of 'coritact race'.

.,

:::

i

1.7.3 Self-Polarised Mho Relay

I

:.,

The mho impedance element is generally known as such characteristic is a straight line on an admittance diagram. It cleverly combines the discriminating qualities of both reach control and direction~lcontrol, thereby .X eliminating the 'contact racet problems that may be encountered with separate reach and directional control elements. This is achieved by the addition of a 2 polarising signal. 'Mho' impedance elements were particularly attractive for $ ; economic reasons where electromechanical relay elements were employed. As a ,!x $ result, they have been widely deployed worldwide for many years and their -:; advantages and limitations are now well understood. For this reason they are still jj emulated in the algorithms of some modern numerical relays.

4

The characteristic of a 'mho' impedance element, when plotted on an R/X .: diagram, is a circle whose circumference passes through the origin, as illustrated r, in Figure 11.9(b). This demonstrates that the impedance element is inherently directional and such that it will operate only for faults3n the forward direction along . . line AB.

'i

\

.

,

.

.,

.-

..

..

.-.

. .. +

:,

,,..

-

%

The impedance characteristic is adjusted by setting Z, the impedance reach, :' along the diameter and cp, the angle of displacement of the diameter from the R:: axis. Angle cp is known as the Relay Characteristic Angle (RCA). The relay, operates for values of fault impedance ZF within its characteristic. . ..: .

It will be noted that the impedance reach varies with fault angle. As the line to be protected is up of resistance and inductance,. its fault angle will be dependent upon the relative values of R and X at the system operating frequency. Under an arcing fault condition, or an earth fault involving additional resistance, such as tower footing resistance or fault through vegetation, the value of the resistive component of fault impedance will increase to change the impedance angle. Thus relay having a characteristic angle equivalent to the line ang!e will under-reach under resistive fault conditions.

( a ) P h a s e comparator i n p u t s

/x

K

/

Restrain i

( b ) M h o impedance c h a r a c t e r i s t i c

Page 15

Relay i m p e d a n c e s e t t i n g Relay c h a r a c t e r i s t i c angle setting GL P r o t e c t e d l i n e PQ Arc r e s i s t a n c e 6' L ~ n eangle

GQ

Figure 1.9: Mho relay characteristic

It is usual, therefore, to set the RCA less than the line angle, so that it is possi to accept a small amount of fault resistance without causing under-rea However, when setting the relay, the difference between the line ar "EQUATION MISSING" and the relay characteristic angle cp must be known. resulting characteristic is shown in Figure 11,9(c) where AB corresponds to length of the line to be protected. With cp set less than 0, the actual amount of protected, AB, would be equal to the relay setting value AQ multiplied by CO! (0-cp). Therefore the required relay setting AQ is given by:

Page 16

Distance Protection Schemes

..

,,

.

12

. . . ,., .

Distance Protection

Conventional time-stepped distance protection is illustrated i n Figure 12.1. One of the main disadvantages o f this scheme is t h a t the instantaneous Zone 1 protection at each end of the protected line cannot be

.

.

.

:,

..

.

in these zones are cleared in Zone 1 time by the protection at one end o f the feeder and i n Zone 2 time (typically 0.25 t o 0.4 seconds) by the protection at the other end o f t h e feeder.

..

..

.

. . . .

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l a ) Srcppcd tirncldisrancc

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characlcri:lics

(b) Trip circuit (solid statc logic) .

..

.. .

This situation cannot be tolerated in some applications. for t w o main reasons: a. faults remaining on the feeder for Zone 2 time may cause the system t o become unstable b. where high-speed auto-reclosing is used. the non-

time' during the auto-reclo;e

cycle for the fault to

cause permanent lockout o f the circuit breakers at each end o f the line section

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Even where instability does not occur, fhe increased duration of the disturbance may give rise t o power quality problems, and may result i n increased plant damage.

.

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Unit schemes of proieciiori tii%icompare the ccnditinns at the two ends of the feeder simultaneously positively identify nhether the fault is internal or external t o the protected section and provide high-speed protection for the whole feeder length. This advantage is balanced by the fact-that the unit scheme does not provide the back up protection for adjacent feeders given by a distance scheme. The most desirable scheme is obviously a combination of the best features o f both arrangements, that is, instantaneous tripping over the whole feeder length plus back-up protection t o adjacent feeders. This can be achieved by interconnecting the distance protection relays a t each end o f the protected feeder by a communications channel. Communication techniques are described i n detail i n Chapter 8.

Zone 2

Zonc 3 (b) Simplilicd logic

The purpose of the communications channel is t o transmit informarion about the system conditions from one end of the protected line t o the other. including requests t o initiate or prevent tripping of the remote circuit breaker. The former arrangement is generally known as a 'transfer tripping scheme' while the latter is generally known as a 'blocking scheme'. However, the terminology o f the various schemes varies widely, according t o local custom and practice.

~eclose~facility is o u t of service: Reversion t o the reach setting occurs only a t the end of the reclaimt For interconnected lines, the Z1X scheme is establis

This scheme is intended for use with an auto-reclose facility, or where no communications channel is available, or the channel has failed. Thus it may be used on radial distribution feeders, or on interconnected lines as a fallback when no communications channel is available, e.g. due to maintenance or temporary fault. The scheme is shown i n Figure 1 2 . 2 .

The disadvantage of the Zone 1 extension scheme is th external faults within the Z1X reach o f the relay result tripping of circuit breakers external to the fault

The Zone 1 elements of the distance relay have t w o settings. One is set t o cover 80010 of the protected line length as in the basic distance scheme. The other, known as 'Extended Zone l ' o r 'ZlX', is set to overreach the protected line, a setting of 120010 of the protected line being common. The Zone 1 reach is normally controlled by the Z 1 X setting and is reset t o the basic Zone 1 setting when a command from the auto-reclose relay is received.

circuit breakers operate.

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A contact operated by the Zone 1 relay element is arranged to send a signal to the remote relay requesting a trip. The scheme may be called a 'direct under-reach transfer tripping scheme', 'transfer trip under-reaching scheme', or 'intertripping under-reach distance protection scheme', as the Zone 1 relay elements do not cover the whole of the line.

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The direct under-reach transfer tr~ppingscheme described above is made more secure by supelvising the received signal with the operation of the Zone 2 relay element before a ~ ~ b w i nang instantaneous trip; as shown in Figure 12.5. The scheme is then known as a 'permissive under-reach transfer tripping scheme' (sometimes abbreviated as PUP 22 scheme) or 'permissive under-reach distance protection', as both relays must detect a fault before the remote end relay is permitted to trip in Zone 1 time.

(bl Faul: within Zonc I cx:cnsion rcach o f distance rclays (doublc circuit lincs) ..

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\;A number of these schemes are available, as described below. Selection of an appropriate scheme depends on i,the requirements'of the system being protected.

----c Signal scnd

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LThe simplest way of reducing the fault clearance time at Ithe terminal that clears an end zone fault in Zone 2 time ;Isto adopt a direct transfer trip or intertrip technique, the 'logic of which is shown in Figure 12.4. !>.

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A fault F i n the end zone at end B i n Figure 12.l(a) results i n operation of the Zone 1 relay and tripping o f the circuit breaker a t end B. A request t o trip is also sent ' t o the relay at end A. -The receipt of a signal a t A initiates tripping immediately because the receive relay contact is connected directly t o the trip relay. The disadvantage o f this scheme is the possibility o f undesired tripping by accidental operation or maloperation o f signalling equipment, or interference on the communications channel. As a result, i t is not c o m ~ [ a n l yused.

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A variant o f this scheme, found on some relays, allows tripping by Zone 3 element operation as well as Zone 2, provided the fault is i n the forward direction. This is sometimes called the PUP-Fwd scheme. Time delayed resetting o f the 'signal received' element is required t o ensure that the relays at both ends o f a single-end fed faulted line o f a parallel feeder circuit have time t o trip when the fault is close t o one end. Consider a fault F i n a double circuit line, as shown i n Figure 12.6. The fault is close to end A, so there is negligible infeed from end B when the fault a t F occurs. The protection at B detects a Zone 2 fault only after the breaker at end A has tripped. I t is possible for the Zone 1 element a t A to reset, thus removing the permissive signal t o B and causing th: 'signal received' element a t B t o reset before the Zone 2 unit at end B operates. I t is therefore.,necessary to delay the resetting sf the 'signal received' element to ensure high speed tripping a t end B.

Z

relays that share the same measuring elements for both' Zone 1 and Zone 2. In these relays, the reach of thca measuring elements is extended from Zone 1 t o Zone 2 S by means o f a range change signal immediately, instead: o f after Zone 2 time. It is also called a n 'accelerated: underreach distance protection scheme'.

4

The under-reaching Zone 1 u n i t is arranged t o send a signal to the remote end o f the feeder i n addition to tripping the local circuit breaker. The receive relay: contact is arranged to extend the reach o f the measurini element from Zone 1 to Zone 2. This accelerates theA fault clearance at the remote end for faults that lie i n the! region between the Zone 1 and Zone 2 reaches. The scheme is shown i n F~gure12.7. Modern distance relays, do not employ switched measuring elements, so the, scheme IS likely t o fall into disuse

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The PUP schemes require only a single communications channel for two-way signall~ngbetween the line ends, as the channel is keyed by the under-reaching Zone 1 elements When the circuit breaker a t one end is open, or there is a weak infeed such that the relevant relay element does not operate, instantaneous clearance cannot be achieved for end-zone faults near the 'breaker open' terminal unless special features are included, as detailed in section 12.3.5.

This scheme

IS

applicable only to zone sw~tchedd~stance

- :.+

. I..:keq .:?;, !,'

r; In this scheme, a distance relay element set t o re?: beyond the remote end of the protected line is used: send an intertripping signal t o the remote end. Howev; it is essential that the receive relay contact is monito!: by a difectional relay contact t o ensure that trippl! does not take place unless the fault is within protected section; see Figure 12.8. The instantane6 contacts of the Zone 2 unit are arranged t o send signal, and the received signal, supervised by zone; operation, is used to energise the trip circuit. scheme is then known as a 'permissive over-rc transfer tripping scheme' (sometimes abbreviate1 'POP'). 'directional comparison scheme', or 'permi: ov~rreachdistance p r o t e c f i o ~scheme'.

9 $

14/06/02

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15-

. . . . . .

w Signal

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7 -

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s i g n a ~ i v c ~ F ~ f p ' p ~

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(a] Signal logic

-

The above scheme using Zone 2 relay elements is often referred to as a POP 22 scheme. An alternative exists that uses Zone 1 elements instead of Zone 2 , and this is referred to as the POP 2.1 scheme.

Since the signallinc channel is keyed by over-reaching Zone 2 elements, the scheme requires duplex communication c'nannels - one frequency for each direction of signalling. If distance relays with mho charac~eristicsare used, the scheme may be more advantageous than the permissive uhder-reaching scheme for protecting short lines, because the resis:ivc coverage of the Zone 2 umt may be greater than that o f Zone 1. To prevent opera:ion under current reversal conditions in a parallel feeder circuit, i t is necessary to use a current reversal guard tirnrr to inhibit the tripping of the forward Zone 2 elements. Otherwise maloptration of the scheme may occur under current reversal conditions. see Section 11.9.9 for more details. It is necessary only when the Zone 2 reach is set greater than 1 5 0 0 f o of the protected line impedance. The timer is used to block the permissive trip and signal send circuits as shown in Figure 12.9. The timer is energised if a signal is received and there is no operation of Zone 2 elemer,:~. An adjustable time delay on pick-up (1,) is usually set to allow instantaneous tripping to take place for any ir,ternal faults, taking into account a possible slower operation of Zone 2. The timer will have operated and blocked the 'permissive trip' and 'signal send' circuits by the time the current reversal takes place. The timer is de-energised i f the Zone 2 elements operate or the 'signal received' element resets. The reset time delay (),I of the timer is set to cover any overlap in time caused by Zone 2 elements operating and the signal resetting at the remote end. when the current i n the healthy feeder reverses. Using a timer in this manner means that no extra time delay is added in the permissive trip circuit for an internal fault.

-

In the standard permissive over-reach scheme, as with 2 the permissive under-reach scheme, instantaneous clearance cannot be achieved for end-zone fau& under . !-: , .t <. . weak infeed or breaker ppen cqnditions. ~ o o v e r c b m e.:..,.;-.. . . . .: . . ,.: .. . . . . this disadvantage, two possibilities exist. . . . . . . .c-..:. ! ,

-

.

':

3.

,

0

. -

The Weak lnfeed Echo feattire available i n s ' 6 m e 1.::: . . protection relays allows theremote relay toecho the trip . 2 signal back to the sending relay even if the appropriate 2 remote relay element has not operated. This caters for conditions of the remote end having a weak infeed or 2 circuit breaker open condition, so that the relevant r C remote relay element does not operate. Fast clearance .L. h for these faults is now obtained at both ends of the line. Q The logic is shown in Figure 12.10. P, time delay (T,)is required in the echo circuit to prevent tripping of the remote end breaker when the local breaker is tripped by 1.2 the busbar protection or breaker fail protection associated with other feeders connected to the busbar. The time delay ensures that the remote end Zone 2 element will reset by the time the echoed signal is received at that end.

--

From

'POP' signal

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Signal transmission can take place even after the remote end breaker has tripped. This gives rise t o the possibility of continuous signal transmission due to lock-up of both signals. Timer T, is used to prevent this. After this time delay, 'signal send' is blocked.

initiated a t any end of the protected section.

A variation on the Weak lnfeed Echo feature is to allow tripping o f the remote relay under the circumstances described above, providing that an undervoltage condition exists, due to the fault. This is known as the Weak lnfeed Trip feature and ensures that both ends are tripped i f the conditions are satisfied. -

The arrangements described so far have used the signalling channel(s) to transmit a tripping instruction. I f the signalling channel fails or there is no Weak lnfeed feature provided, end-zone faults may take longer t o be cleared.

to two variants of the scheme.

Blocking over-reaching schemes use an over-reaching distance scheme and inverse logic. Signalling is initiated only for external faults and signalling transmission takes place over healthy line sections. Fast fault clearance occurs when no signal is received and the over-reaching Zone 2 distance measuring elements looking into the line operate. The signalling channel is keyed by reverselooking distance elements (23i n the diagram, though relay used]. which zone is used depends o'n-the An ideal blocking scheme is shown.in Figure 12.11.

as a 'directional comparison blocking scheme' or a 'blocking over-reach distance protection scheme:

(a1 D ~ s r a n c c l r ~ r ncharaclcristics c

- 12 -

Chacncl In 5 c ~ i c c

a Signal scnd

ZI

-

A fault at F 1 is seen by the Zone 1 relay elements at,, both ends A and B; as a result, the fault is cleared instantaneously at both ends o f the protected l i n q

-

Zone 1 elements.

-

Signalling cquipmcnl -End A

Signalling cquipmcnl

-End B

(cl Signalling arrangcmcn(

196

.

,.

-

.

.

-

2

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-

-

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nal transmission takes place, since the ernal and the fault is cleared i n Zone 1 time a t after the short time lag (STL) a t end A.

relay elements a't end B associated w i t h the 2 2 elements a t end A f r o m tripping, the

neously by the protection o n line section B-C,

lity o f Zone 2 elements initiating tripping and the I c ~ k i n g Zone 3 elements failing t o see an I fault. This would result i n instantaneous ing for a n external fault. When the signalling nel is used for a stabilising signal, as i n the above takes place over a healthy line section is used. The sigrialling channel uld then be more reliable when used i n the blocking e-than, i n tripping mode.

I n a practical application, the reverse-looking relay elements may be set w i t h a forward offset characteristic t o provide back-up protection for busbar faults after the zone time delay. It is then necessary t o stop the blocking signal being sent for internal faults. This is achieved b y making the 'signal send' circuit conditional upon nonoperation o f the forward-looking Zone 2 elements, as shown i n Figure 12.1 3.

.!???T,:.'<;;::'

$;tg&$Q? .::,... _-:.. _.*_ .. . . .. .. .,.: -1.. ' :,>: ,:.., $ ..: ,.- ,.~.%....

Blocking schemes, like t h e permissive over-reach scheme, are also affected b y the current reversal i n the healthy feeder due t o a fault i n a double circuit line. If current reversal conditions occur, as described i n section 11.9.9, it may be possible for the maloperation o f a breaker on the healthy line t o occur., To avoid this, the resetting o f the 'signal received' element provided i n the blocking scheme is time delayed. The timer w i t h delayed resetting (t,) is set t o cover the time difference between the maximum resetting time o f reverse-looking Zone 3 elements and the signalling channel. So, if there is a momentary loss o f the blocking signal during the current reversal, the timer does n o t have time t o reset in the blocking mode t r i p circuit and n o false tripping takes place.

:

-.

p.

. .

:'&ientialt h a t , t h e operating times o f the various .bPskilfully co-or'dinated f o r all system conditions, @thatsufficient time is always allowed for the receipt K=:blocking signal from t h e remote end o f the feeder. #.this is n o t done accurately, the scheme may t r i p for an $ernal f a u l t or alternatively, the end zone tripping imes may be delayed longer than is necessary.

This is s ~ m i l a rt o the BOP 22 scheme described above. except that an over-reaching Zone 1 element is used i n the logic, instead o f the Zone 2 element. It may also be known as the BOP Z1 scheme.

f the signalling channel fails, the scheme must be $ranged t o revert t o conventioaal basic distance uotection. Normally, the blocking mode trip circuit is upervised b y a 'channel-in-service' contact so that the locking mode trip circuit is isolated when the channel is ut of service. as shown i n Figure 12.1 2.

The protection a t the strong infeed terminal will operate for all internal faults, since a blocking signal is not received from the weak infeed terminal end. In the case of external faults behind the weak infeed terminal, the reverse-looking elements a t that end will see the fault current fed from the strong infeed terminal and operate, initiating a block signal t o the remote end. The relay a t the strong infeed end operates correctly without the need for any additional circuits. The relay a t the weak infeed end cannot operate for internal faults, and so tripping of that breaker is possible only b y means o f direct intertripping from the strong source end.

-

c/I, I

I +-

2 0

I I

0

L

c,

L.

r;

2 -2 Q

. 12.

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The permissive over-reach scheme described i n Section ;:.,:. : -,-.. . 12.3.4 can be arranged t o operate o n a directional :.;:+-.):..:,:? . . comparison unblocking principle by providing additional .;: . . . .,.:;, circuitry i n the signalling equipment. I n this scheme ,:::''' -;',.": -. . . . . .... .:.'-. (also called a 'deblocking overreach distance protection '

(b] Solid % t a l c logic of rcnd circuit

....

...

-

;Chap12 exe

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!

scheme'), a continuous block (or guard) signal is transmitted. When the over-reaching distance elements operate, the frequency of the signal transmitted is shifted t o an 'unblock' (trip) frequency. The receipt o f the unblock frequency signai arid thc pera at inn crf overreaching distance elements allow fast tripping to occur for faults within the protected zone. In principle, the scheme is similar t o the permissive over-reach scheme. The scheme is made more dependable than the standard permissive over-reach scheme by providing additional circuits i n the receiver equipment. These allow tripping to take place for internal faults even i f the transmitted unblock signal is short-circuited by the fault. This is achieved by allowing aided tripping for a short time interval, typically 100 to 150 milliseconds, after the loss of both the block and the unblock frequency signals. After this lime interval, aided tripping is permitted only i f the unblock frequency signal is received. This arrangement gives the scheme improved security over a blocking scheme, since tripping for external faults is possible only i f the fault occurs within the above time interval of channel failure. Weak lnfeed terminal 'conditions can be catered for by the techniques detailed i n Section 12.3.5. In this way, the scheme has the dependability of a blocking scheme and the security of a permissive overreach scheme. This scheme is generally preferred when power line carrier is used, except when continuous transmission of signal is not acceptable.

On normal two-terminal lines the main deciding factors in the choice o f the type of scheme, apart from the reliability o f the signalling channel previously discussed, are operating speed and the method of operation of the system. Table 12.1 compares the important characteristics o f the various types of scheme. i'~~~~;j.:,,,,i;Ilq.@p

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Spccd with in-wnicc t e t i n g

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Modern digital or numerical distance relayrare provided with a choice o f several schemes i n the same relay. Thus scheme selection is now largely independent of relay selection, and the user is assured that a relay is available with all the required features to cope'with changing system conditions.

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The protection scheme for a power system should cover the whole system against all probable types of fault. Unrestricted forms of line protection, such as overcurrent and distance systems, meet this requirement, although faults i n the busbar zone are cleared only after some time delay. But if unit protection is applied to feeders and plant, the busbars are not inherently protected.

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Busbars have often been left without specific protection, for one or more of the following reasons: a. the busbars and switchgear have a high degree of reliability, to the point of being regarded as intrinsically safe b. i t was feared that accidental operation o f busbar protection might cause widespread dislocation of the power system, which, i f not quickly cleared. would cause more loss than would the very infrequent actual bus faults c. i t was hoped that system protection or back-up

protection would provide sufficient bus protection i f needed I t is true that the risk of a fault occurring on modern metal-clad gear is very small, but i t cannot be entirely ignored. However, the damage resulting from one uncleared fault, because of the concentration of fault MVA, may be very extensive indeed, up to the complete loss of the station by fire. Serious damage to or destruction of the installation would probably result i n widespread and prolonged supply interruption. Finally, system protection will frequently not provide the cover required. Such protection may be good enough for small distribution substations, but not for important stations. Even i f distance protection is applied to all feeders, the busbar will lie i n the second zone of all the distance protections, so a bus fault will be cleared relatively slowly, and the resultant duration of the voltage dip imposed on the rest of the system may not be tolerable. With outdoor switchgear the case is less clear since. although the likelihood of a fault is higher, the risk of widespread damage resulting is much less. In general then, busbar protection is required when the system protection does not cover the busbars, or when, in order

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t o maintain power system stability, high-speed fault clearance is necessary. Unit busbar protection provides this, with the further advantage that if the busbars are sectionalised, one section only need be isolated to clear a fault. The case for unit busbar protection is i n fact strongest when there is sectionallsation.

The majority of bus faults involve one phase and earth, but faults arise from many causes and a significant number are interphase clear of earth. In fact, a large proportion of busbar faults result from human error rather than the failure of switchgear components. With fully phase-segregated metalclad gear, only earth favlts are possible. and a protection scheme need have earth fault sensitivity only. In other cases, an ability to respond to phase faults clear of earth is an advantage, although the phase fault sensitivity need not be very high.

incidence, amounting to no fault per busbar in twenty years, it is clear that u the stability of the protection is absolute, the degr disturbance to which the power system is li subjected may be increased by the insta protection. The possibility of incorrect operation h the past, led to hesitation in applying bus protectio has also resulted in application of some very co systems. Increased understanding of the response of differential systems t o transient currents enable systems to be -applied w i t h confidence i n their fundamental stability. The theory of differential protection is given later i n Section 15.7. Notwithstanding the complete stability of a correctly applied protection system, number of reasons. These are: a. interruption of the secondary circuit of a transformer will pr might cause trippin relative values of circuit load and effective setting. It would certainly do so during a through fault, producing substantial fault current i n the circuit in question

Although not basically different from i t h e r circuit protection, the key position of the busbar intensifies the emphasis put on the essential requirements of speed and stability. The special features o f busbar protection are discussed below.

b. removal of busbar faults in less time than could be achieved by back-up line protection, with the object of maintaining system stability Some early busbar p r o t e c t i ~ n schemes used a low impedance differential system having a relatively long operation time, of up to 0.5 seconds. The basis of most modern schemes is a d~fferentialsystem using either low impedance biased or high impedance unbiased relays capable of operating in a time of the order of one cycle at a very moderate multiple of fault setting. To this must be added the operating time of the tripping relays, but an overall tripping time of less than two cycles can be achieved. With high-speed circuit breakers. complete fault clearance may be obtained in approximately 0.1 seconds. When a frame-earth system is used, the operating speed is comparable.

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b. a mechanical shoc cause operation, although the likelihood occurring- with modern numerical sch reduced c. accidental interference'with the relay, aris a mistake during maintenance testing, may lead to operation

Busbar protection is primarily concerned with: a. limitation of consequential damage

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In order to maintain the high order of integrit for busbar protection, i t is an almost invariable practice I to make tripping depend on two independent measurements of fault quantities. Moreover, if the tripping of all the breakers within a zone is derived from common measuring relays, t w o separate elements must -: be operated at each stage t o complete a tripping i operation. Although not the relays are separated reasonable accidental m relays simultaneously is possible.

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The two measurements may be made by two similar differential systems, or one differential system may be checked by a frame-earth system. by earth fault relays energised by current transformers in the t neutral-earth conductors or by overcurr Alternatively. a frame-earth system may be checked by earth fault relays. If two systems of the unit or other similar t y they should be energised by separate transformers in the case of high impedan differential schemes. The duplicate ring CT mounted on a common primary *

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The 5tability of bus pr02ection is of paramount importance. Bearing in mind the low rate of fault

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be maintained t h r o u g h o u t the he case of l o w impedance, biased differential mes t h a t cater for unequal ratio CTs, the scheme be energised from either one or t w o separate sets o f

'isthen n o more t h a n t h a t o f normal circuit protection, so no duplication is required a t this stage. N o t least among the advantages o f using individual tripping relays is the

Security o f both stability and operation is obtained by providing three independent channels (say X, Y a n d Z) whose outputs are arranged i n a 'two-out-of three' voting arrangement, as shown i n Figure 15.1.

A number o f busbar protection systems have been devised: a. system protection used t o cover busbars

through a common multi-contact tripping relay. b. frame-earth protection c. differential protection

d. phase comparison protection e. directional blocking protection

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? t h e section switch trips b o t h the adjacent zones. This has sometimes 'been avoided i n the past b y giving the

zone on the faulty side o f the section switch

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Of these, (a) is-suitable for small substations only, while (d) and (e) are obsolete. Detailed discussion o f types (b). and (c] occupies most o f this chapter.

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Early forms o f biased differential protection for busbars. such as versions o f 'Translay' protection and also a scheme using harmonic restraint, were superseded b y unbiased high impedance differential protection.

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is obtained a t the expense of seriously delaying the bus This practice is therefore not generally favoured. Some var~ationsare dealt w i t h later under the more detailed scheme descriptions. There are many combinations possible, b u t t h e essential principle is that n o single accidental incident of a secondary n a t u r e shall be capable o f causing a n unnecessary trip o f a bus section.

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Security aqainst maloperation is only achieved by increasing the amount o f equipment that is required t o function t o complete a n 0peration;'and this inevitably increases the statistical risk t h a t a tripping operation due t o a f a u l t may fail. s u c h a failure, leaving aside the question o f consequential damage, m a y result i n disruption o f t h e power system t o an extent as great, or greater, than would be caused by a n unwanted trip. The relative risk of failure o f this kind may b e slight, but i t has been thought worthwhile i n some instances t o provide a guard i n this respect as well.

The relative simplicity o f the latter, and more importantly the relative ease w i t h which its performance can be calculated. have ensured its success u p to the present day.

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But more recently the advances i n semiconductor technology, coupled w i t h a more pressing need t o be able t o accommodate CT's o f unequal ratio, have led t o the re-introduction o f biased schemes, generally using static relay designs, particularly for the most extensive and onerous applications. Frame-earth protection systems have been i n use for many years, mainly associated w i t h smaller busbar protection schemes at distribution voltages and for metalclad busbars (e.g. SF6 insulated busbars). However, i t has often been quite common for a unit protection scheme t o be used i n addition, t o provide t w o separate

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System protection that includes overcurrent or distance systems will inherently give protection cover t o the busbars. Overcurrent protection will only be applied t o relatively simple distribution systems, or as a back-up protection, set t o give a considerable time delay. Distance protection will provide cover for busbar faults w i t h its second and possibly subsequent zones. In both cases the busbar protection obtained is slow and suitable only for limiting the consequential damage.

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The only exception is the case of a mesh-connected substation, i n which the current transformers are located a t the circuit breakers. Here, the busbars are included, i n sections, in the. individual zones o f the main circuit protection, whether this is o f unit type or not. I n the special case when the current transformer_s are located on the line side o f the mesh. he circuit protection will n o t cover the busbars i n the instantaneous zone and separate busbar protection, known as mesh-corner protection, is generally used - see Section 15.7.2.1 for details.

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Frame leakage protection has been extensively u s e d i n the' past i n many different si~uations. There are several variations of frame leakage schemes available, providing busbar protection schemes w i t h different capabilities. The following sections schemes have thus been retained for historical and general reference purposes. A considerable number of schemes are still i n service and frame leakage may provide an acceptable solution i n particular circumstances. However, the need t o insulate the switchboard frame and provide cable gland insulation and the availabiliry of alternative schemes using numerical relays, has contributed t o a decline in use o f frame leakage systems.

The iwitchgcai must b e insulated i s a standing it on concrete. Care must founddtion bolts do not touch the sufficient concrete must be cut permit grouting-in w i t h no risk o f touching metalwork :;.$ The insulation to earth finally achieved will not be high, $ :.$.:23 a value of 10 ohms being satisfactory. $;::.....s.

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When planning the earthing arrangements of a frame- .',(:?: leakage scheme, the use of one common electrode for $ :; both the switchgear frame and the power system neutral '.$.? ::&,. point is preferred, because the fault path would :$; otherwise include the two earthing electrodes i n seriel I f either or both of these are of high resistance or have inadequate current carrying capacity, the fault current may be limited to such an extent that the protection equipment becomes inoperative. In addition, if the >;& electrode earthing the switchgear frame is the offender, the potential of the frame may be raised t o a dangerous value. The use of a common earthing electrode of adequate rating and low resistance ensures sufficient current for scheme operation and limits the rise i n f r a m e i s .$ :$ potential. When the system is resistance earthed, the ;g earthing connection from the switchgear frame is made

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This is purely an earth fault system and, i n principle. involves simply measuring the fault current flowing from the switchgear frame t o earth. A current transformer is mounted on the earthing conductor and is used to energize a simple instantaneous relay as shown in Figure 15.2. No other earth conncctions of any type, including incidental conncctions t o structural steelwork are allowed. 'This rcquircmcnt is so that: a. thc principal carth connection and current transformer arc not shunted, thereby raising the

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This risk is small i n practice

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2-253

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Under external fault conditions, the current I , flows through the frame-leakage current transformer. If the ' insulation resistance is too low, sufficient current may , . : flow t o operate the framc-leakage relay, and, as the check ....feature is unrestricted, this will also operate t o complete .:-'the . trip circuit. The earthresistance between the G r t h i n g :-'electrode and true earth is seldom greater than IR,so with 10R insulation resistance the current I , is limited to 10% o f . t h e total earth fault current I , and 12. For this for the reason, the recommended minimum se;:ing scheme is about 30% of the minimum earth fault current.

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If it is inconvenient t o insulate the section switch frame o n one side, this switch may be included i n t h a t zone. It is then necessary t o intertrip the other zone after approximately 0.5 seconds if a fault persists after the zone including the section switch has been tripped. This IS illustrated i n Figure 15.5.

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lniul~tion

All cable glands must be insulated, to prevent the circulation o f spurious current through the frame and earthing system by any voltages induced i n the cable sheath. Preferably, the gland insulation should be provided i n t w o layers or stages, with an interposing layer of metal, t o facilitate the testing of the gland insulation. A test level o f 5kV from each side is suitable.

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Section 15.6.1 covered the basic requirements for a system t o protect switchgear as a whole. When the busbar is divided into sections, these can be protected separately, provided the frame is also sub-divided, the sections mutually insulated, and each provided w i t h a separate earth conductor, current transformer and relay. Ideally, the section switch should be treated as a Separate zonc, as shown i n Figure 15.4, and provided w i t h either a separate relay or t w o secondaries o n the frame-leakage current transformer, w i t h an arrangement t o t r i p b o t h adjacent zones. The individual zone relays trip their respective zone and the section switch.

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For the above schemes to function it is necessary to have a least one infeed or earthed source of supply, and i n the latter case it is essential that this source o f supply be connected t o the side o f the switchboard not containing the section switch. Further, if possible, it is preferable that an earthed source of supply be provided on both sides of the switchboard, in order to ensure that any faults that may develop between the insulating barrier and the section switch will continue to be fed with fault current after the isolation o f the first half o f the switchboard, and thus allow the fault to be-removed. Of the two arrangements, the first is the one normally recommended, since i t provides instantaneous clearance of busbar faults on all sections of the switchboard.

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as operation due to mechanical shock or mistakes made ,.,$ by personnel. Faults in the low voltage auxiliary wiring must also be prevented from causing operation by !# %: passing current to earth through the switchgear frame ':..$: A useful check is provided by a relay energised by the, system neutral current, or residual current. I f the neutral ,f check cannot be provided, the frame-earth relays should ': .<+9 &,.
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When a check system is used, instantaneous relays can $ be used, with a setting of 30% of the minimum earth ,$ fault current and an operating time at five times setting 3 . ..\, of 15 milliseconds or less. ij Figure 15.7 shows a frame-leakage scheme for a metalclad switchgear installation similar to that shown in Figure 15.4 and incorporating a neutral current check ! a; obtained from a suitable zero sequence current source, ;s'< such as that shown in Figure 15.2.

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It is not generally feasible to separately insulate the metal enclosures of the main and auxiliary busbars. Protection is therefore generally provided as for single bus installations, but with the additional feature that circuits connected to the auxiliary bus are tripped for all faults, as shown in Figure 15.6.

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The protection relays used for the discriminating an check functions are of the attracted armature type, wit; two normally open self reset contacts. The tripfln circuits cannot be complete unless both ,,.:r discriminating and check relays operate; this is becay: the discriminating and check relay contacts connected in series. The tripping relays are attracted armature type.

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fis usual t o supervise the satisfactory operation o f the

The scheme may consist of a single relay connected t o the bus wires connecting all the current transformers in parallel, one set per circuit, associated with a particular zone, as shown i n Figure 15.8(a). This will give earth fault protection f o r the busbar. This arrangement has often been thought t o be adequate.

h t c c t i o n scheme with audible and visual alarms and &$cations for the following:

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busbar faults

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c. busbar protection out o f service

If the current transformers are connected as a balanced group for each phase together with a three-element relay, as shown i n Figure 15.8(b), additional protection for phase faults can be obtained.

d. tripping supply healthy *-

'

e. alarm supply healthy

enable the protection equipment-of each zone t o be out of service independently during maintenance periods, isolating switches - one switch per zone - are '.provided i n the trip supply circuits and an alarm cancellation relay is used.

The phase and earth fault settings are identical, and this scheme is recommended for its ease of application and good performance.

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'The Merz-Price principle is applicable to a multi-terminal Zone such as a busbar- The principle is a direct i . application of Kirchhoffs first law. Usually, the 2f- circulating current arrangement is used, in which the current transformers and interconnections form an 1;....-analogue of the busbar and circuit connections. A relay $.F?cQ?nected -across t h c . 0 bus .wires represents a fault c;path:in the-prima-w.system i" the analogue and hence i s . ~~'%bt,n&gised until i f a u l t occurs o n t h e busbar; it then . . ii3eceiyes an input that, in principle at Icast, represents .. ;::the fault current.

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Each section o f a divided bus is provided with a separate circulating current system. ~h~ zones so formed are switches, so that a fault over-lapped across the the latter tripthe two adjacent zones. hi^ is illustrated in~i~~~~ 15.9. Tripping two zones for a section switch fault can be avoided by using thetime-dela~ed technique Section .. 15.6.2. However instantaneous . . operation is the . - preferied - . .

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For double bus installation, the two busbars will be ... treated as separate zones. 'The auxiliary busbar zone will ;:::::.',;..-.' ....:',... overlap the appropriate main busbar zone at the bus .:.;. . . . - .: .:,';::-. . .. -,, ; coupler. ..,.;:s....,.:.I,.; ,.:....... ;.: -:;:,:. ,,:- .:. . :;? ''.:; : Since any circuit may be transferred from one busbar to ;:+?i<~:l3:+;;!f:. .-. . . . .. . . . . the other by isolator switches, these and the associated :;.!$.:;?& -;, ..... ?; l/..,;~L:::?:, ..:. tripping circuit must also.,be switched to the appropriate .. :,..::< ..: :'..+~

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Figure 15.10(a) shows the ideal arrangement i n which,...: both the circuit and busbar zones are overlapped leaving!: no region o f the primary circuit unprotected.

zone by 'early make' and 'late break' auxiliary contacts. This is t o ensure that when the isolators are closing, the auxiliary switches make before the main contacts of the isolator, and that when the isolators are opened, their main contacts part before the auxiliary switches open. The result is that the secondary circuits of the t w o zones concerned are briefly paralleled while the circuit is being ransferred: these t w o zones have i n anv case been . :-:. . . ........ ,.::.2.:\c~, .. united through the circuit isolators during the transfer . - ..... ?:?>:$;: operation.

a small region o f the priniary circuit unprote unprotected region is typically refcrred t o as the 's zone: The fault shown will cause operation o f the busbar protection, tripping the circuit breaker, but the fault will continue t o be fed from the circuit, if a source of p is present. It is necessary for the bus protecti intertrip the far end of the circuit protection, if the is o f the unit type.

.:;.y:<:.?: :..\ ..

. . ...... . . . . .

Ideally, the separate discriminating zones should overlap each other and also the individual circuit protections. The overlap should occur across a circuit bteaker, so that the latter lies i n both zones. For this arrangement i t is necessary to install current transformers on both sides o f the circuit breakers, which is economically possible with many but not all types o f switchgear. With both the circuit and thc bus protection current transformers on the same side o f the circuit breakers, the zones may be overlapped a t the current transformers, but a fault between the CT location and the circuit breaker will not .be completely isolated. This m a t t e r is important i n all . . . . . :. . . . . .:., .. . ... . .1 .. .... . . switctigear,to '.wl%ch these . conditions apply, and is :: .i:-;.::, paaiculaily impohant.in the case of outdopr switchgear - . . . . .. -. . where . :se.parately 'mbirnted. muiti-secondary current . .. . ,!s. - transformers are generally 'used. The conditions are. ;,o. shown i n Figure 15.10.

With reference -to Figure 15.10(b), special 'short

technique may be used, particularly when th the fault is i n the switchgear connections generator; the latter is therefore tripped electrical shut down on the mechanical side so as to

,

'

:.,

i

*. L a

-':/::.

The protection of busbars.in.mesh c o h e gives rise t o additional considerations location. A single mesh corner is s . . . .

'L W1

Norc I : Only 1 connection lo (hc rncsh corncr pcrmiltcd

(a) CT arrangcrncnlr for protection including mesh corner

: j i

<$@ .....

.>?$

;, :.g , ,

a. Currcnt lransformcrs mounted on bolh rider of brcakcr -no unprolcclcd region b. Currcnt transformers mounted on c ~ r c u side ~ l only of brcakcr

Nocc 2: Multiplccircuils may bc conncclcd lo rhc mesh corncr (b1 CT arrangcmcnlr for protccrion additional mesh corncr prolcclion required

-law11 shown not cleared by circuil prolcction 1

.

.

c , ) a . 7 ~s t l i c c . : c c cr,i,r!! f > * c g k c r *):.:,.

. -..- .

--

..

A

1

. . ..

.

. . ... . .. . ..

.

.

.

.

32-253

17/06/02

'

9:48

Page 241

:.

.

.

!.,ti

,.I : I.

.. . .

.

-$-

onnection t o the mesh is

An equivalent circuit, as i n Figure 15.12, can represent a irculating current system. ...

.-

-- ---...-.. -. - -.-...... -. -

.

--..--- -. - .... -.......

.

.

-.

I '\$ I hout any means of determining the faulted 'connection. Protection CT's must therefore be located on . : each connection, as shown in Figure 15,11(b). This leaves

t

R a

hown i n Figure 15.11 (b).

RLG

RR .

. ..... . .

. .

Id>

considerations that have to be taken into account are detailed i n the following sections.

............: : . . ! 2 . E : : ~ ; G < ! ! ? : > i! : : < ; : ; i .-.!,"..

;.2

k;g,

!.:.~;:, -:c3 .c, > . .."

.'I::;

: .

.

G: c ~ ~ f < i i ~ Z <~U ; ~< < LO: : :Z

>k>:C.5

~ h , current transformen are replaced inthe diagram by of flux .

is not' detrimental as long as it linear range of the

-;

ideal current transformerj feeding an equivalent circuit . ............ . that represents the ,magn,etising losses and seco":da,iy=

winding

.

.

.resistance, ..and

a i s o . t h e resistan,&

'

,,

:

:j:,-~;~~~;~:~.~:;i: ..,: ..

df .;I.:-.;.-

j:;

:-.;.

the convecting .leads. ~h~~~. circuits can then be ,:GI~. . ..:..1 interconnectedas shown, with a relayconnected to the. ':'.'. '.;f junction points t o form the complete equivalent circuit

2

.,

. 4

Q

1 1

region of the characteristic; this not in itself a spill output from a pair of balancing current transformers provided that are identical and equally b e of A group of transformers, though the same design, will not be completely identical, but a important factor is inequaliOl of burden in the case of a differential system for a busbar, an external fault may be fed through a single circuit, the current being supplied to the busbar through all other circuits. The faulted circuit is many times more heavily loaded than the others and the corresponding current transformers are likely to be heavily saturated, while those of the other circuits are not. Severe unbalance is ., therefore probable, which, with a relay of normal burden, could exceed any acceptable current setting. For this reason such systems were at one time always provided dclay. This practice is, however, no longer

1

may

Saturation has the effect of lowering the exciting and is assumed take place severeiy in current transformer H until, at the limil. the shunt impedance becomes and the " can produce output, This condition is represented by a short circuit. shown i n broken line, across the exciting impedance. it should be noted that this is not the equivalent of a physical short circuit, since it is behind the winding resistance .

b

23 a7

15-

Applying the Thkvenin method of solution, the voltage developed across the relay will be given by:

I=

"I

RR+R,.,i +RUN

..

. :<,dG!,:,a

T5.! . . . . . . . . . .. . . . . .. ,.:......c . . ..:........ ,~,!<

..

The current through the relay is given by:

... ;$:;..>.. ?, ........... -. . ..:. 2.

..\IU.

.: ,,.+,

;;. .

,

.,?'

,,,:,.

?:-:.4c-.:,",

!5 . 2

,

..........

:,:

C-id,

141

.. ? ;

. I .

.. .

,: .

.. . .-... .

.:$,.

...<,::;S;t.i'

.., ..;,.:;.: ,.-.L,.,..,..: :\i_&~y>Tp >, ,'.,.";*,.' jy;j .. . ,?*<.~.?.>,?, %.5.*'. ..; . ,;5:<.;: ::-'. .;. ; .&d9".+$i,?,.

-

I . r . - # l * . .

;

",%.7,.

,'.."'

;::$!;$&ii$.,*"..

If RR is small. IR will approximate to IF which is ?$@<@$@ unacceptable. On the other hand, i f RR is large IR is jr.7~:c:22~ reduced. Equation 15.2 can be written, with little error. - ' ' ~ ~ ~ < ? ~ f % ? ~ . .,+' ?.,.& > :;.:; ...1 .. as follows: .:.-....,...... ...::> .,.. . . .. ,.;<; . .A,, . . . . ..,,,,':.k.j,; ,.: :.:

... .- . . . . . . . . . . .

U

I

.xe&+,;::pz-.~ ..:, ,,.&&:

....

R ~ + R f f i + R ~ ~ i

asible to calculate the spill current that may ortunately, this is not necessary; an alternative approach provides both the necessary information and the technique required to obtain a high performance.

Pr.rr,ri..

-

>,:. ~+;$;>;~,5~;~<. ,T<-27-,A... . ,..

- ~ , ( R u i +&H) .,.f ">I!

-

2

a.

'

.

,*a. .....$,,,.'k L?:

-

:j

I ;

..

..---.. . ..-

- ;a!i.,,i

-253

17/06/02

9:48

I # = - -V, = RR

Page 2 4 2

RL + RCI.= lead + CT winding resistance

I,(R,+Rm)

.RR

... E g u o t i o n !5.3

or alternatively:

It remains to be shown that the setting chosen.. suitable.

It is clear that,by increasing RR, the spill current ZR can be reduced below any specified relay setting. RR is frequently increased by the addition of a series-connected resistor which is known as the stabilising resistor. It can also be seen from Equation 15.4 that it is only the voltage drop in the relay circuit at setting current that is important. The relay can tie designed as a voltage measuring device consuming negligible culrent; and provided its setting voltage exceeds the value Vf of Equation 15.4, the system will be stable. In fact, the setting voltage need not exceed V/. since the derivation of Equation 15.4 involves an extreme condition of unbalance between the G and H current transformers that is not coppletely realised. So a safety margin is built-in i f the voltage setting is made equal to Vf

-

(range 0.7 - 2.0)

The current transformers will have an excitation curve which has not so far been related to the

winding resistance, with the maximum secondary fa current flowing through them. Under in-zone fa conditions it is necessary for the current transformers produce sufficient output to operate the relay. This will be achieved provided the CT knee-point voltage exceeds. the relay setting. In order to- cater for er to specify that the current transformers knee-point e.m.f. of at least twice the necessaq'settin voltage; a higher multiple is of advantage i n ensuring high speed of operation. .

It is necessary to realise that the value of I/to be inserted in Equation 15.4 is the complete function of the fault current and the spill current IR through the relay, in the limiting condition, will be of the same form. I f the relay requires more time to operate than the effective duration of the d.ct transient component, or has been designed with special features to block the d.c. component, then this factor can be ignored and only the symmetrical value of the fault current need be entered in Equation 15.4. I f the relay setting voltage. V,, is made equal to VJ that is, I/ (RL + RCr], an inherent safety factor of the order of two will exist.

.

carrying primary cuiwnt or n strictly speaking be vecto arithmetically. t t can be expressed as:

IR = IS + l l I C s

cycle and with no special f~aturesto block the d.c. component, it is the r.m.s. value of the first offset wave

IR

=

eflective setting

n

=

number ofparallel - conilecred CT's

Equation 15.4 as:

Equoliorr 1 5 . 5

=

stabiliry of schetne

=

relay circuit voltage setting ,--

/ .

,

.

p__.__-€d A . t . r , r i . m

N ~ f w a r kP r . r r r t i . m

Cailr

Fi; E' TI.

y .. , .

b!

a. phase-phase faults give o n l y 8 6 % o f the threephase fault current

. .-

,.

..

'

':h resistance

reauce raulr currents somewhat c. a reasonable margin should be allowed to ensure that relays operate quickly and decisively -

,

~tis desirable that the primary effective setting should not graceed 30% of the prospective minimum fault current. p earth fault %.protection, the minimum earth fault current should be considered, taking into account any earthing impedance .? iy that might be present as well. Furthermore, in the event 1 of the inter.f. is available In in the earth g;? n u l r currenc. Ine prlmary operating current must e not greater than 30°/0 of the minimum se earth fau;t current. In order to achieve ed operation, it is desirable that settings should r, particularly in the rase of the solidly of the power system. The transient i n conjunction with wnfavourable residual can cause a high degree of saturation and utput, possibly leading to a delay of several cycles time of the element. 91 to the natural

8.:

This will not happen to any large degree if the fault current is a larger multiple of setting; for example, if the fault current is five times the scheme primary operating current and the CT knee-point e.m.f. is three times the relay setting voltage, the additional delay is unlikely to exceed one cycle. The primary operating current is sometimes designed to exceed the maximum expected circuit load in order to reduce the possibility of false operation under load current as a result of a broken CT lead. Desirable as this safeguard may be, it will be seen that i t is better not to increase the effective current settingtoo much, as this will sacrifice some speed; the check feature inany case, maintains stabilitv. An overall earth fault scheme for a large distribution board may be difficult t o design because of the large number of current transformers paralleled together, which may lead to an excessive setting. It may be advantageousinsuch a case to provide a three-element phase and earth fault scheme, mainly to reduce the number of current transformers paralleled into one group.

Ems-high-voltage substations usually present no such problem. Using the voltage-calibrated relay, the current consumption can be very small. A simplification can be achieved b y providing one relay per circuit, all connected to the CT paralleling buswires:

Zonc R

.......... *.

. .:

.....

r21.

1'

Zonc AIZ

I

1

. /

''

'1

Zonc A I I Bus wircs Zonc A12 Bur wircl Zonc Bur wi Chcck 208 Bur wir

~ u l l rn aclay w m e ar chcct

A11 First main burbar A12 Second main burbar K Rcrcwc burbar

L V ~ Cnr

r rcla

u m c ar chcci

--...,..-... ", samc as chcck 5tabiliring Rcrirtor Iligh lmpcdancc Ctrculattng Currcnt Rclav

53

17/06/02

9:48

Page 2 4 4

.......................

..............................

..........

IS30 74

80 87 95

Zonc indicating rclay Alarm cancclla:~on relay D.C. volts supcw~sionrelay High impcdancc circulating current relay Bus wires supcwision rclay

area and reduces the risk o f accidental operation. i ..... :;. ; i':>, : . : : .:;

Schemes for earth faults only can be checked by a frame-

. . .

. .-.

.

-

LI L2

Zonc bus wircs shorting relay Control selector switch Indicating lamp protection in scrvicc Indicating lamp pcorection out of scrvicc

,

subdivision being necessary. For phase fault sche the check will usually be a similar type of scheme ap to the switchboard as a single overall zone.

This enables the trip circuits t o be confined to the least

earth system, applied t o the switchboard as a whole, no

CSS

, 244

A set of current transformers separate from those use the discriminating zones should be provided. No" switching is required and no current transformers

.

-4-

......

N,rr.rk

Pr.rrrri.m

U A,r.n.ri..

C

: zone i n bus-coupler and busCT Scconciarf Circuits

CT secondary circuit up to the :tions will cause an unbalance i n equivalent t o the load being carried by the c i r c u i t Even though this degree o f -* . ~ 'r i o u s output is below the effective setting the '&dition cannot be ignored, since it is likely to lead t o a- . b i l i t y under any through fault condition. .

.PL

h r v i s i o n can be carried out t o detect s;ch conditions $ connecting a sensitive alarm relay across the bus &es of each zone. For a phase and earth fault scheme, mjnternal three-phase rectifier can be used t o effect a bthmation of the bus wire voltages o n to a single alarm lcment; see Figures 15.13 and 15.14. . '

I

cubicle. It is possible that special circumstances involving onerous conditions may over-ride this convenience and make connection t o some other part o f the ring desirable. Connecting leads will usually be not less than 710.67mm (2.5mm1), but for large sites or in other difficult circumstances it may be necessary to use cables of, for example 711.04mm (6mm1] for the bus wire ring and the CT connections t o it. The cable from the ring to the relay need not be of the larger section. When the reserve bar is split by bus section isolators and the t w o portions are protected as separate zones, it is necessary to common the bus wires by means o f auxiliary contacts, thereby making these two zones intb one when the section isolators are closed.

. .:

he alarm relay is set so that operation does not occur ~iththe protection system healthy under normal load. ubject t o this proviso, the alarm relay is made as wsitive as possible; the desired effective setting is 125 imary amperes or 10% of the lowest circuit rating, hichever is the greater. -

This section provides a summary of practical considerations when implementing a high-impedance busbar protection scheme.

nce a relay of this order o f sensitivity is likely t o -,::; !:! ::: :: ; .,I. .;:;!:':! .i:r:!j,.;:::,. . . . .. %rate;during thrdugh faults; time delay, typically of For normal circumstances, the stability level should be I- :-';: - . i&;:s@cd"ds; is to . . avoid unn&cessary alarm, . . . . : designed t o correspond to the switchgear rating; even if . . - : jnals. . - . -. .. ... - .. . the available short-circuit power i n the systemis much

a

.8.5 krrangc:-- .i - ;

...

.!-.

Car

:i.;:

...... '.. i:

;s shown in Equation 15.4 how the setting voltage for liven stability level is directly related to the resistance the CT secondary leads. This should therefore be )t to a practical minimum. Taking i n t o account the lctical physical laying of auxiliary cables, the CT bus 'es are best arranged i n the form of a ring around the tchgear site. double bus installation, the CT leads should be taken :ctly t o the isolator selection switches. The usual ting of cables on a double bus site is as follows:

I

a. current transformers to marshalling kiosk b. marshalling kiosk to bus selection isolator auxiliary switches

less than this figure, it can be expected that the system will be developed up to the limit of rating.

-5

Current transformers must have identical turns ratios. but a turns error of one in 400 is recognised as a reasonable manufacturing tolerance. Also, they should preferably be of similar design; where this is not possible the magnetising characteristics should be reasonably matched.

&.

I

I

!

b

E, C

m

- .

2 rq 15.

Current transformers for use with

high impedance protection schemes should meet the requirements of Class PX of IEC 60044-1. . I

The setting voltage is given by the equation 2.

interconnections between marshalling k i d s to form a closed ring

rclay for each zone is connected to one point of the bus wire. For convenience of cabling, thc main zonc ys will be connected through a multicorc cable vcen the relay panel and the bus section-switch rhalling cubicle. The reserve bar zone and the check : relays will be connected together by a cable ling t o the bus coupler circuit breaker marshalling

v,> I f ( R , + Red .I..,. . ,., .., , .,;:

where:

VI

If

R,. Rcr

=

!':.., . .,..,.. .. .,.<

relay circuit voltage

- steady-state through fault curreirt CT

=

CT secondary ruinditrg resistntrce

.f. *:I'

.:!,.?;*

,!:

:I,

., . , . il. ;3 *>:.

ICSiStetICe

=

I-.

>

,

i

LC). .

. : ,..!I .. ;I$ ,.i .

.: ,.wk;

I.,

.

: I$I.*

!

."..L,?.: ' .

*I

', ,~ [,:c;.,: ,.?, .: , I.,,.

'hap15-232-253

9:4a

Page 246

- ,. ,..:. . . .'

,\L

.

17/06/02

.?&;.<,:;...,?u"4'+ .,.G*.g

,

: ,. -. ;;

f5.&.6.<

.,.+x?,<

:$<.:

secondary condition is:

This is given by the formula

. - $2: ...:brs .,.,'.

;.*.>,>

7..:vr<-b ..

.:'..:'.

.The effective setting of the relay is given by

I f =fault current Ic = exciting k current a t knee - point voltage

-.

VK= knee - point voltage

..

Is = relay-circuit current settirlg Ic = CT s exritatiol~current at voltage seffi~lg simple combination of burden and exciting impedance

n = number of CTS i n parallel

by the CT turns For the primary fault setting multiply IR ratio.

These formulae are therefore to be regarded only as guide to the possible peak voltage. With large current transformers, particularly those with a low sesonda current rating, the voltage may be very high, above

It is clear from Equations 15.4 and 15.6 that i t is

advantageous to keep the secondary fault current low; this is done by making the CT turns ratio high. I t is common practice to use current transformers with a secondary rating of 1A. . I t can be shown that there is an optimum turns ratio for .. . ;.I the current transformers; thiswalue depends on all the . . application but is generally about 200011. ' ' . though a lower ratio, f o r instance 40011, is often . employed; the use of the optimum ratio can result. in a ,I.:. considerable reduction in the physical size of the current sz 0 . :.: transformers. '

-=

..

E,

4

. . .. ,~:~.~.z,,.>

?

L',.:,:

:.;.:..

:

. ,

.

:,

,. . .

, .,/..

;

,

3

-* +,

'a

s

15 .

.

When the burden resistance is finite although high, an

where:

V p= peak voltage del)elopcd knee-poit~tvoltage

VF= prospective voltagc i n abserlce ojsaturation

.

.

This formula does not hold for the open circuit condition and is inaccurate for very high burden resistances that approximate to an opcn circuit, because simplifying assumptions used in the derivation of the formula are not valid for the extreme condition.

:

.

,: . ,

c; ...?--

where C is a constant depending on dimensions and . a constant in the range 0.2-0.25. '

voltage setting depends on t h e value of ~ ; . i ' n keep the shunting effect t o a minimu recommended to use a non-linear resistor with a value of

.,

..-c.-. approximate formula for the peak voltage is:

VK =

v = CP

.,:,.., , ,: ,: .

Under in-zone fault conditions, a high impedance relay constitutes an excessive burden to the current transformers, leading to the development of a high voltage; the voltage waveform will be highly distorted but the peak value may be many times the nominal saturation voltage.

Z

ceramic non-linear resistor in parallel having a characteristic given by:

Another approach applicable to the opcn circuit -

Instantaneous attracted armature relays are used. Simple fast-operating relays would have a low safety factor constant in the stability equation, Equation 15.5, as discussed in Section 15.8.1. The performance is improved by series-tuning the relay coil, thereby making the circuit resistive in effect. Inductive reactance would tend to reduce stability, whereas the action of capacitance is to block the unidirectional transient component of fault current and so raise the stability constant. An alternative technique used in some relays is to apply the limited spill voltage principle shown in Equation 15.4. A tuned element is connected via a plug bridge to a chain of resistors; and the relay is calibrated in terms of voltage.

The principles of low impedance differential protection have been described in Section 10.4. including the principle advantages to be galned by the use of a bias.

32-25:

&nique.

17:05/02

9:48

Page 2 4 7

Most modern busbar protection schemes use

e

principles of a check zone, zone selection, and . gements can still be applied. Current . transformer secondary circuits are not switched directly by isolator contacts b u t instead by isolator repeat relays after a secondary stage of current transformation. These switching relays form a replica of the busbar within the protection and provide the complete selection logic.

En .

'kr_ '

tis=

3 !:, ,.I

;!< With some biased relays, the stability is not assured by.

I:...

the through current bias feature alone, b u t is enhanced by the addition of a stabilising resistor, having a value .: :; which may be calculated as follows.

,

;:

'

The through current will increase the effective relay

i minimum operating current for a biased relay as follows:

where:

IR = eflecfive 1nii1i111uii1o p r n t i ~ i g currer~t - .

;-

G = relay s e n i i ~ gc u n e i l t

It must be recognised though that the use of any technique for inhibiting operation, to improve stability performance for through faults, must not be allowed t o diminish the abilii\i of the relay to respond to ir~iernaifauiu.

For an internal fault, and with no through fault current flowing, the effective setting (IR) is raised above the basic relay setting (Is) by whatever biasing effect is produced by the sum of the CT magnetising currents flowing through the bias circuit. With low impedance biased differential schemes particularly where the busbar installation has relatively few circuits, these magnetising currents may be negligible, depending on the value o f Is.

. . .

The basic relay setting current was formerly defined as the minimum current required solely i n the differential circuit to cause operation - Figure 15.45(a]. This $@@:1i&3&. approach simplified snalysis of performance. b u t was .. considered t o be unrealistic, as i n practice any current -y*+c::7..~. . . .flowing i n the differential circuit must flow i n a t least . . one half o f the relay bias circuit causing the practical 25, minimum operating current always to be higher than the .... ,nominal basic setting current.. As a.. result,.-a: : .... ._:................ later: :...-...,. +.- . . ..,L....r2,; .-.' . definition, as shown i n Figure l5.l:5(b) w+.developed;: -;.i;~~;:~~.rl..i;~;r;~~~. . . . . . . . . . . . . . . . ..:-:. ......... .. ....

.;:s&:,;._.-:: ~

'.

.

.:._

From Equation 15.4, the value of stabilising resistor is given by:

where: -

LH

+

N

=

CT ratio

<;!I

t3 It is interesting to note that the value of the stabilising resistance is independent of current level, and that there would appear to be no limit to the through-faults stability level. This has been identified [15.1] as 'The Principle of Infinite Stability: The stabilising resistor still constitutes a significant burden on - the current transformers during internal faults. An alternative technique, used by the MBCZ system described i n Section 15.9.6, is to block the differential measurement during the portion of the cycle that a current transformer is saturated. If this is achieved by momentarily short-circuiting the differential path, a very low burden is placed on the current transformers. In this way the differential circuit of the relay is preventtd from responding to the spill current.

:-4 -..

Conversely, ifneedsto be. appreeiif& tkit later definition of relay setting cu.rrent, whicti. flows . : -..$:;i= ;:!.:-.:...-:-::-..-.:-'-I through at least half the bias circuit, the notional mini- i ~ r :".rl mum operation current i n the differential circuit alone o .L.. is somewhat less, as shown in Figure 15.15(b). % . 'a .L.. Using the d e f i n i t i w presently.applicable, the effective minimum primary operating current 2 Q

:.

As IF is generally much greater than Is, the relay = B k approximately. effective current, IR

,

:.--:-..' ..c> .* . - , ........ . ..;.. . . . . . . . . . - . . .;, applying' .thi~.1:6:.....1<.~....~~...r. ,.,-.-. ...........

.

i

(al Suocrxdcd definition

(bl Currcnt

dcfinition

:

.

hapis-232-253

17/06/02

9:54

.

Page 2 4 8

Unless the minimum effective operating current of a scheme has been raised deliberately to some preferred value, it will usually be determined by thy check zone, when present, as the latter may be expected to involve the greatest number of current transformers in parallel. A slightly more onerous condition may arise when two discriminating zones are coupled, transiently or otherwise, by the closing of primary isolators. ., It is generally desirable-to 'attain an effective primary operating current that is just greater than the maximum load current, to prevent the busbar protection from operating spuriously from load current should a secondary circuit wiring fault develop. This consideration is particularly important where the check feature is either not used or is fed from common main CTs.

For some low impedance schemes, only one set of main CT's is required. This seems to contradict the general principle of all busbar protection systems with a check feature that complete duplication of all equipment is required. but it is claimed that the spirit of the checking principle is met by making operation of the protection-, as directional', dependent on two different criteria such . . . . . . ... and d.iffere?tialmeasllrements.

isolators may provide the latter.

auxiliary relays within the protection. Theserelays form

j

'

them to be connected into this busbar replica. transformers available per circuit Where the facility of a check zone is still required, this can still be achieved with the low impedance biased protection by connecting

:. .'! :

.In the MBCZ scheme, described i n Section

15.9.6, the provision of auxiliary CT's as standard for ratio matching also provides a ready means for introducing the check feature duplication at the auxiliary CT's and onwards to the relays. This may be an attractive compromise when 3nly one set of main CT's is available.

. ..

.

..,. :

..

. L. . . . . . ,. . .... . .

In low impedance schemes the integrity of the CT secondary circuits can also be monitored. A current operated auxiliary relay, or element of the main protection equipment, may be applied to detect any unbalanced secondary currents and give an alarm after a time delay. For optimum discrimination, the current

. . .. ,

setting of this supervision relay must be less than that of the main differential protection.

.. .

In modern busbar protection schemes, the supervision of the secondary circuits typically forms only a part of a comprehensive supervision facility.

...

.. .

,

:'.

. .. ..

f,

1

,. ,

..~. . 1

. -. I .

,.,.::.,

7

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g:.

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It is a common modern requirement of low impedance schemes that none of the main CT secondary circuits should switched. in the previously convcptional manner, to match the switching of primary circuit isolators.

.

.

..

.!!

.

.

range of CT mismatch. 188

..

.

,. :., .,:,;;<.:;

- TYl"

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A separate module is used for each circuit breaker and also one for each zone of protection. In addition to these

. ,.\ior::,

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.

particular busbar installation. Additional modules can be added at any time as the busbar is extended.

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.

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F;scre i s . 17: J y 2 c :,!3CZ b:iI;o! i c : c r : ! < . n >ir::b,;i:;.i t.'.:.. . berwccfl c8.rco8.:::?;+<,:? o,>d p,:t;,:c:+,:,; ? :? ;:,> ..,,,. .. L..

.

plug-in buswire connections

......-........

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.

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2. ... ..: ;I: figure ,&:. '?

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15.17 shows the correlation between the circuit

'-,.$;,.beakers . and the protection modules for a typical double ~ ~ % u s.b 8 r i n s t a l l a t i o nIn . practice the modulesare mounted @?nia,,multi-tier rack or cubicle: i+._

.

,

'

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ETthat is plugged i n t o the back o f the modules. There are $3' five main groups o f buswires, allocated for: i.,'. I :

i. protection for main b u s b a ~

'cI "

y',::

ii. protection for reserve busbar

,

.r... .. . . , ;4

Ill.

.

" .. -..: }, r .J

protection for the transfer busbar. When the reserve busbar is also used as a transfer bar then this group o f buswires is used

6p? 5. .;

iv. auxiliary connections used by the protection to combine modules for some of the more complex , kq. busbar configurations

+,,!'

F&,.;:

V.

protection for the check zone

,

;.&:

E;: One extra module. n o t shown i n this diagram, is plugged h.?: into the multicore bus. This is the alarm module, which ??!
5.':"

. >

:

@;,All zones o f measurement arc biased by the t o t a l current y,k+, B. .flowing t o or f r o m the busbar system via the feeders. h i s cnsurcs t h a t all zones o f measurement w i l l have similar fault sensitivity under all load conditions. The bias is derived from the check zone and fixed a t 20% , w i t h a characteristic gencrally as shown i n Figure . lS.lS(b). Thus some ratio mismatch is tolerable.

.

.

.

.

'

.,

::

_;

.

.

.

The traditional method for stabilisinga differential relay is t o add a resistor t o the differential path. Whilst'this improves stability it increases the burden on the current transformer for internal faults. The technique used hi the MBCZ scheme overcomes this problem. The MBCZ design detects when a 'CT is saturated and short-circuits the differential path for the portion o f the cycle for wk,ich saturation occurs. The resultant spill current does not then f l o w through the measuring circuit and stability is assured. This principle allows a very low impedance differential circuit t o be developed t h a t will operate successfully with relatively small CT's.

. .

. .

If the CT's carrying fault current are n o t saturated there will be ample current i n the differential circuit t o operate the differential relay quickly for fault currents exceeding the m i n i m u m operating level. which is adjustable between 20%-200% rated current.

When the only CT(s) carrying internal fault current become saturated, i t might be supposed that the CT saturation detectors may completely inhibit operation by short-circuiting the differential circuit. However, the resulting inhibit pulses remove only an insignificant portion o f the differential current, so operation of the relay is therefore virtually unaffected.

'

Out of scrvicc

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-

.-;.

0

- ---

. . . . . . .. . .

As shown in Figure 15.18, each measuring module contains duplicated biased differential elements and also a pair of supervision elements. which are a part of a comprehensive supervision facility.

u

2

This arrangement provides supervision of CT secondary circuits for both open circuit conditions and any i . impairment of the element to operate for an internal fault, without waiting for an actual system fault 9, to show this up. for a zone to operate it is Q necessary for both the differential supervision element and the biased differential elementto operate. F~~ a circuit breaker to be tripped it requires the associated : . l j . ; : . ,,,. main zone to be ooerate,-j and alsothe ,-heck . ., .. * ........ . . -... . ....: . zone, as shown in Figure 15.19. .."' :. -. ."."

=

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cheek zonc

Main zonc

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rhis is avoided by using a 'master/follower' arrangerneri< By making the impedance of one of the measuring elements very much higher than the other it is possibletp ensure that one of the relays retains its original minimum operation current. Then to ensure that both the ~ ~ connected zones are tripped the trip circuits of the zones are connected in parallel Any measuring unit can

Me's

~

have the role of 'master' or 'follower' as it is selectable by means of a switch on the front of the module. .

.

.

.

. , . .

.

.

... ....

.

.;I

Serious damage may result, and even danger to life, if,;

These schemes are qenerally based on the assumptiol

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.,

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.

circuit breaker fails to open when called upon to do S$ To reduce this risk breaker fail protection schemes wefl .$ developed some years ago. ,

i +vc

.-..a,-.-

to operate the two busbar sections as a single bar:-:& ' !: fault currgnt will then divide betweenthe two meas&Gn,@ elements in the iatio'of their impedances. If both of th$ two measuring elements are of low and equal impedang f! I. the effective minimum operating current of the scheme $ . will be doubled. . .*<

. . . . . . .. . . .,

.*'

....I

; 7..

..........;.......

.

,

,...,

..

When two sections of a busbar are connected together by isolators i t will result in two measuring elements being connected in parallel when the isolators are closed

n$

i t has failed to function. The circuit breakers in the stage back in the system are then automatically trippet For a bus coupler or section breaker this would invc tripping all the infeeds to the adjacent zone, a that is included in the busbar protection scheme.

fat

.:I 13 ,. r!

17/06/02

9:54

+I+

Page 2 5 1

.

fibre optic link

Ccntral Unit CU

Systcm Communication Nctwork

PU: Pcriphcral Unit CU: Ccntral Unit

... ' .-.. p;;:

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r.

: -'.

. . . ., .. . .

.

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c.

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d. dead zone protection . .

The application of numerical relay technology t o busbar !.'.. protection has lagged behind that of other protection. \?
2,

feederr. interface units at a may be used w i t h the data transmitted t o a single centrally located peripheral unit. The central unit performs the calculations required for the protection functions. Available protection functions are: -

a. protection b. backup overcurrent protection c. breaker failure

In addition, monitoring functions such as CB and isolator monitorinq, disturbance recordinq and transformer supervision ace.provided: . :... - . . . . .... . . . .. ... ... .

.

.. .

. . . . . . .

.

.

.

.

.

.

-

. .

.

.

Because .- o f , . the : , distributed :-topology. used, r.:l".' :.:;.: . ...... - . . . . . . ~ ~ n c h r o n i s a t i oon f the 'me&urernents. .taken-'.by t h e ' :&;!-:;: . .-:;. .. .-pe;ifiheral u"its .is:of vital iipo.rt+ce. '.'rX1high&ability; numerically-c6ntr;11e& oscillator is fitted-in'each o f the central and peripheral units, with time synchronisation . . . . . between them. I n the event o f loss o f the o . . synchronisation signal, the high stabilityof the oscillator % i n the affected feeder unit(s) enables processing o f the .. . ~ncomingdata to continue without significant errors .. Q : :2 . . . until svnchronisation can be restored.

;;,

,

. .

; --

,

~

.:.z

,

-

The peripheral units have responsibility for collecting the required data, such as voltages and currents, and processing it into digital form for onwards transmission to the central unit. Modelling o f the CT response is included, t o eliminate errors caused by effects such as CT saturation. Disturbance recording for the monitored feeder is implemented, for later download as required. Because each peripheral unit is concerned only with an individual feeder, the protection algorithms must reside in the central unit. The differential

algoriihm can be much more

sophisticated than w i t h earlier technology, due t o improvements in processing power addition to calculating the sum of the measured currents, the algorithm can also evaluate differences between successive current samples, since a large change above a threshold may indicate a fault - the threshold being choscn such that normal load changes, apart from inrush conditions do not exceed the threshold. The same

.

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.

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:CbaplS-232-253

17/06/02

9:5i

Page 2 5 2

considerations can also be applied t o the phase angles o f currents, and incremental changes i n them. One advantage gained f r o m the use o f numerical technology is the a h i ! i q )ls easi!\t re-configure the protection t o cater for changes i n configuration o f the substation. For example, addition o f a n extra feeder involves the addition o f an extra peripheral unit, the fibre-optic connection t o the central u n i t and entry via the M M I o f the new configuration i n t o the central unit. Figure 15.21 illustrates th,e latest numerical technology employed.

In considering the introduction o f numerical busbar protection schemes, users have been concerned w i t h reliability issues such as security and availability. Conventional high impedance schemes have been one o f the main protection schemes used for busbar protection. The basic measuring element is simple i n concept and has few componen:s. Calculation o f stability limits and other setting parameters is straightforward and scheme performance can be predicted w i t h o u t the need for costly testing. Prac;ically. h i g h impedance schemes have proved t o be a very reliable f o r m o f protection.

I n contrast, modern numerical schemes are more .complex w i t h a much greater range o f facilities and a :\ m u c h high component count. Based o n low impedanc bias techniques, and w i t h a greater range o f facilities t ,. <.+-. set, setting calculations can also be more complex. :::.> . ..: However, studies o f t h e comparative reliability of conventional high impedance schemes and .modern .~..numerical schemes have shown that assessing relative ....!;I. reliability is not quite so simple as i t might appear. The ->&? ..!*' .. numerical scheme has t w o advantages over its older ,;$;;i counterpart:

i6 ,::-'

.:+ ?

a. there is a reduction i n the number. o f external components such as switching and other auxiliary relays, rcany o f the f u n c t i o n s o f which ?re performed i n t e r n a l l y w i t h i n the software alqorithms

'..: . , ; : A

>;

b. numerical schemes include sophisticated monitoring features which provide alarm facilities i f the scheme is faulty. In certain cases, siniularion of the scheme functions can be (performed on line f r o m the CT inputs through i o the tripping o ~ i p d t c and thus scheme functions can be checked on a regular basis t o ensure a f u l l operational mode is available a t all times Reliabil~tyanalyses using fault tree analysis methods have examined issues o f dependability (e.q. the ability t o operate when required) and security (e.g.-the ability n o t t o provide spurious/indiscriminate operation). These analyses have shown that:

-

a. dependability o f numerical schemes is better than conventional high impedance schemes b. security o f numerical and conven:ional impedance schemes are comparable

high

I n addition, an important feature o f numerical schemes is the in-built monitoring system. This considerably improves t h e potential availability o f numerical schemes compared t o conventional schemes as faults w i t h i n the equipment and i t s operational state can be detected and alarmed. W i t h the conventional scheme, failure t o reinstate the scheme correctly after maintenance may not be detected u n t i l the scheme is required t o operate. In this situation, i t s effective availability is zero until it is detected and repaired.

15.1 The Behaviour o f Current Transformers subjected t o Transient Asymmetric Currents a n d the Effects o n Associated Protective Relays. J.W. Hodgkiss. ClGRE Paper Number 329. Session 15-25 J'une 1960.

,

-. ""

Motor Protection

lNTRODUCTlON

serious loss of production may result. .

The following table indicates typicall protection depending on the size of the motor. However, other factors should be considered when selecting motor protection, for example importance of

PROTECTION Contactor

1. Fuses 2. Fuses + ' ~ h e r r n a l Overload + U N

'I MW-3MW

Options - Stalling & Undercurrent

overcurrent +

phase and earth faults. The protection must be able to distinguish between abnormal conditions and normal motor operation. Therefore, it is important to understand the behaviour of the motor under certain conditions to be able to apply protection successfully. For example, the magnitude and duration of the starting current affects the application of overload protection; the magnitude and maximum allowable duration of stalling current in relation to those of staring current determir.~e whether separate stalling protection is required.

THERMAL OVERLOAD PROTECTION The tolerance to overload of motors depends on the motor design and differs considerably iri Practice. The risk of damage of the insulation depends on the temperature. It is very difficult il not impossible to cover all types and ratings of motors with different applications, variety (1; 4

Page 1

If a motor is assumed to be a homogeneou and dissipating heat at a rate directly proportional temperature at any instant is given by :

b '15

where T,,

ii

= final steady teniperature

f = heating time constant

This assumes a thermal equilibrium in the form : Heat developed = Heat stored + Heat dissipated. Temperature rise is proportional to the current square.

Thus T

7

=

K I ,: - ! 1 - e

I, is that current \vhich produces the rated temperature rise T,; when flo\vs continuously in the motor. whent="C

.

.

.

For an overload current 1 the temperature rise is given by : , .

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For the motor not to exceed the rated temperatu rhe motor can withstand the current I is obtained by equating equations (1) and (2) with t = OC in

i L

equatim (1).

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I-lcncc K I , , -

=

ii.

g. s;. Rr

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or

t =

r.10~~

1

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....:....

-.. ti'

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rload protection should satisfy the above r :notor current or a percentage of it, depending on the motor design.

is an over-simplification to regard a motor as a homogeneous .body. It actually comprises ral parts each with a characteristic surface area, mass, heat capacity, thermal conductivity rate of heat production. The temperature rise of different parts or even of various point in e same part may be very uneven. However, it is reasonable to consider that the current-time lationship follows an inverse fashion. b h i l e infrequency overloads of short duration may not damage the motor, sustained overload ;of a few percent may result in premature ageing and failure of insulation so that the time lag !:..characteristic of the device is of vital importance in permitting the normal starting duty and /:pmviding close sustained overload protection for the motor at the same time.

C::,

1. :.STARTISTALL PROTECTION t.

t

:A Direct-On-Line machine (DOL) will typically draw a starting current of approximately 6 times \full load current for a period defined by the machines starting time. This is because the :impedance of the machine is related to the slip frequency, which varies during start up; the :impedance beirlg smaller at low speeds where the slip is larger. With normal 3-phase supply, should a motor stall when running, or be unable to start due to excessive load, it will draw a current equivalent to the locked rotor current. On the basis of starting current being equal to locked rotor current it is not possible to distinguish between 3-phase stalling and healthy starting by monitoring the current alone. In the majority of cases, the starting time of a normal induction motor is less than the maximum stalling. time allowable to avoid excessive deterioration of the motor insulation.. Under this. condition it is possible to discriminate on a tim.e basis between the two and provide' protection against. stalling. In applications where the stalling time is less than the startingtime 'such' as motors driving high inertia loads, it is more difficult to discriminate between a healthy start and a stall condition. A separate stalling relay may be required depending on the type of overload xotection relay used and the ratio of normal starting time to the allowable stall time. The following conditions may be examined lssume startrng current = stall current

ST ~ S L

= maximum starting time

= niaximum allowable stall time

Thermal relay operating time at the same current level < t , ~but

In this case the thermal relay can Protect the motor against 3-phase stall, no separate stalling relay is required.

1s

.

'

..

ii)

Thermal relay operating time at the same current level > t , ~and

.

A

ST In this case no stalling protection is provided by the thermal overload relay even though the stall time is greater than the starting time. A separate stalling relay is required. If the difference between tsL and t s ~ is adequate to cater for relay errors a simple single phase definite time overcurrent relay may be used.

,Thermal

'1 ----------------

.

,

i

b

:?, . .,

I

Is current setting < locked rotor current hut > load current ts time setting < t s ~but > t s ~

. . ..

....

overcurrent ..

.

I

starting cilaracteristic Motor

I

IS

OIC = overcurrent TD = time delay 86 = trip relay tsL > TD > tsT

1

- a a 'TRIP

.z<

-:L4

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'3 ;i

In this case a separate stalling relay in the form of a definite time over-current relay and a shaft monitoring device are required. The latter is used to check the motor speed while the relay measures the motor current. Instead of the overcurrent relay a simple definite time delay relay may also be used as shown below :

Page 4

'<

.,2

-

j-e

..

*a

Use of a tachoswitch monitor with a definite time delay relay:-

+

o

TD

o

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.

-43-

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.

The tacho contact will open when the set speed (say 10% of rated speed) is reached. It m x t operate well within TD. MSD = Motor switching device auxiliary contact, closed when the motor is switched on.

F.i!i! TRIP

,

:.

TD < tSL

-

ii)

i

Use of a tachoswitch monitor with a definite time overcurrent relay:-

This offers more reliabil~ty

TD < tsL OIC < stall current, > load current

-

iii)

-0-OcFTRl P

Use of a 2-stage definite time overcurrent relay:-

TDI TD2 OIC

-

-10-

TRIP

Page 5

>t s ~ load current

No protection during motor starting TDI is continuously period. energised when the motor is in operation.

.

.

If tsL > tsT the same arrangement can be used in which case stalling protection is provided during the starting period. This method provides additional advantage for motors with different hot and cold stall times in that TD2 cah be set to less than hot stall time irrespective of cold stall :, time.

'

TD1

'ST

(TD1 + TD2)

< tsL (cold)

OPERATION ON UNBALANCE SUPPLY The supply voltage to a 3-phase induction motor can become unbalanced due to such reasons as single phase load, imperfect transportation of feeders etc. The degree of unbalance is small in normal installation except when onephase become ope'n circuited. This would not affect at first sight, the motor to any large extent, but a small voltage unbalance could produce a much larger negative phase sequence current in the winding due t o the relative small negative phase sequence impedance of the machine compared with the positive phase sequence impedance. Consider the following equivalent circuits for positive and negative phase sequence currents, the magnetising impedance being neglected: . ... .. .....,: & ,?

-

,

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....-:,: ..,. -...<<

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R'2

-R'2

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With positive phase sequence voltages a rotating field will be set up and the rotor will rotate in the direction of rotation of the filed giving a slip s and slip frequency sf. With negative phase sequence voltages the field will rotate in the opposite direction cutting a rotating rotor conductor at almost twice the frequency. The actual frequency of negative phase sequence voltage and current in the rotor circuit is (2 - s)f. From the equivalent circuits: Motor +ve sequence impedance at a given slip s

= [ ( R ~+ R ' ~ )

+ (XI + X',

,

)~j"

when s = 1 at standstill.

Page 6

Motor -ve sequence impedance at a given slip s

,

(R, + i

~

' 22

~

' 22

-

+ (x, +

l2

when s << 1 at normal running speed

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1 1"

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The value of resistance is generally much less than the leakage reactance.

Therefore

j neglecting the resistance term the motor -ve phase sequence impedance at normal running

:

speed can be approximated to the +ve phase sequence impedance at standstill.

i.:

; . ~ tnormal running speed : i'.

+ve sequence impedance -ve sequence impedance

starting current normal load current

-

If a motor has a starting current 6 x the full load current, the -ve sequence impedance would be about 116'~of the +ve sequence impedance. Therefore if 1 pu +ve sequence voltage applied to the motor would produce 1 pu of +ve ;.;..sequence current, the same 1 pu of -ve sequence voltage would produce 6 pu - ve sequence !::.'current. Consequently, if there is 5% -ve sequence voltage present in the supply it would result .' . . :z:;in-an . approximate 30% of -ve sequence component of current.

I.--

~. ..

.

'The ac resistance of the rotor conductor to the induced -ve sequence current is greater than the dc resistance due to the higher frequency [(Z-s)fl causing skin effect. The heating effect of -ve sequence current is therefore greater and increases the motor losses. The machine output must be reduced to avoid overheating. Because of the reversed rotation of the magnetic field due to -ve sequence current, a small -ve torque is also produced. As mentioned previously one unit of -ve phase sequence current has a greater heating effect than one unit of +ve phase sequence current, this unequal heating effect should be taken into account in the design of a thermal characteristic based on:

I equivalent =

JF"17

where 11 = +ve sequence component 12 = -ve sequence component N = a fixed constant A typical value of n in motor protection relays is 6. This value has been carefully chosen to provide adequate protection to both the stator and rotor windings for all designs of motor without causing nuisance tripping.

Page 7

I.

..

..

.-. .. ..

.

_

. ... -_ -

.

..

.

.

. .. .

LOSS OF ONE PHASE WHILE STARTING J

Assume a balanced 3-phase supply: Normal starting current

IA 2 (VnN.Z)/2= Standstill impedance per phase of the motor

With one phase open-circuited ssy C phase :

i.e, Starting current with one phase open circuited = 0.866 x normal starting current.

Page 8

i.e. + ve sequence current = Similarly, I 2 =

1 3

- (ItA +

1

- normal starting current.

2

2

a IaB )

normal starting current. ..,..; .'--. For

delta-connected winding motors the actual line starting current with one phase open circuit

e:. is the same as a wye-connected machine : iZ.,

:Ir. :

1

For delta-connected winding motors the line starting current with one 7 ;. ? . . .:. . .phase .. open circuit is the same as a 5;-bye-connected machine:-

ii;. actual

I<..:
i.

.

Normal starting current =

I.

V AS ,fi x z

VAB Actual starting current = 21122

i

-

A-

--

x normal starting current

2

= 0.866 x normal starting current Note that one winding will carry twice the current in the other two windings

! ; t

Page 9

SINGLE PHASE STALLl'NG PROTECTION On loss of one phase supply while starting the motor will remain stationary.. It has been sho the motor will draw a current equal to 0.866 x the normal starting current. Therefore, if measuring the total stator current is used it must have a time delay longer than the starting ti of the motor. If the allowable stall time at that level of current is less than the starting ti simi!ar arr=lr?gementsas in the case of 3-phase stalling protection have to be used. However, it has also been shown that the negative phase sequence component present in current is equal to half the normal starting current. A negative phase sequence curren can therefore detect this condition. In the CTM relay an instantaneous negative sequence current detector is fitted. It has a setting of 2-8 x rated current. If a setting of normal starting current the relay will detect single phase stalling condition.

LOSS OF ONE PHASE WHILE RUNNING It is difficult to shown in simple mathematical terms the behaviour o f the motor when one ph supply is lost with the motor running due to the complex nature of the s l i ~ calculation and possibility of additional negative phase sequence current being fed into the motor from par equipment. However, the following would happen: i)

Heating increases considerably due to high rotor losses caused by the -ve s current

ii)

Output of motor is reduced and depending on the load it could stall altogether. -

iii)

. ..

...

Motor current increases..

.

..

,

.

.. .

REVERSED PHASE SEQUENCE STARTING Ir: many installations such as lift motors and conveyors, protection is occasionally requ ensure correct direction of rotation. Although not damaging to the motor this can be detri to the process. Under reversed phase sequence conditions the relay is designed to respond to the ex negative phase sequence component of current. A number of methods can be disconnect the motor from the supply during this condition Instantaneous Negative Sequence Overcurrent Relay - This will respond very quic load current is sufficient on the system. Time Delayed Thermal Trip - As mentioned previous the thermal overload prot influenced by the negative phase sequence component of the current, this elemen more benificial for smaller loads.

. . .,

.+: ."

..:.;:$ ..

I.

,

The disadvantage of the above methods is that in order for them to operate the motor must be:; switched on, dpending on the inertia of the motor it may start to turn in the wrong direction. this is unacceptable then a negative phase sequence voltage monitoring device can be used- *. This device will monitor the phase rotation of the incoming supply to the motor and if interlocked.: with the motor switching device will prevent closure onto a revese phase sequence supply. his': ,z approach is also used when the motor can only draw very low load currents.

Page 70 -

-

-

)LOW VOLTAGE PROTECTION P

A; !for induction motor the torq;e developed is approximately proportional to the square of the Tapplied voltage. Low voltage level prevents motors from reaching rated speed on starting or 'may draw heavy current on losing speed. Some form of undervoltage protection is therefore desirable with suitable time delay to disconnect the motors when severe low voltage conditions tpersist for more than a few seconds. The time delay is required to prevent tripping on ' momentary voltage dips

I INSULATION FAILURE .The majority of stator winding faults are the result of prolonged or cyclical overheating which causes the insulation to deteriorate. Most faults are cleared by instantaneous earth fault protection as the windings are generally surrounded by earthed metal. Sensitivity of the earth fault relay is limited by the spill current from residually connected CTs during starting, usually 20%. Most other faults are cleared by thermal or unbalance protection. Instantaneous overcurknt units if fitted protect only against terminal flashovers and other heavy short circuits. This is because of the high settings necessary to prevent maloperation on starting current surges. For motors above say 1MW differential protection may be used to give high speed clearance of phase and earth faults. This usually takes the form of high impedance differential or biased differential. 6 current transformers are required with 2 per phase at the two ends of winding.

'

.:;,..-. . .

:'. .,.SELF (r .. .

BALANCE TYPE DIFFEREN'TIAL PROTECTION

I 41

I

I

I

I

I

i

1

fb

1

-

A

An alternative is to use self balance type different~alprotection arrangement Using instantaneous current relays.

' ,

shown above

If conductors are placed reasonably bncentric w~thinthe window of the core balance current W ~ t hthis low spill current and a

; : transformers, spill current can be kept to a minimum. .-. ~

1 ,

Page 11

reasonably indepenaence of CT ratio to full load a lower fault setting could be achieved than:. conventional high impedance circulating current differential schemes. Disadvantages :

.,;q

i)

the necessity of passing both ends of each phase winding through the CT and hence the need for extra cabling on the neutral end.

ii)

to avoid long cabling position of CTs are restricted to the proximity of the machine output terminals in which case the cable between the machine output terminals and controlling . switchgear might not be included within the differential zone.

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OPERATION WITH FUSED CONTACTORS

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Where the motor is switched via a fused contactor, the interrupting capacity of the contactor ':, must be taken into consideration. In general they will not be rated to break the maximum fault current. In this case it is important to prevent the protection attempting to operate the contactor '% above its maximum rating. This is usually achieved by disabling all instantaneous tripping .'. 3 elements and time co-ordinating with the associated fuije. This is illustrated in the following .? ,. diagram:

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TIME

Ts .

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ELEMENT

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Page 12

RING FAILURE PROTECTION ings can suffer from both electrical and mechanical failure: rical Interference - can result in an induced voliage and corresponding circulating aring, it is important to take precautions against this, for example adequate ng of equipment. -

anical Failure - results in increased friction, generating heatirig and eventually failure of

f bearings are detailed below:

-

this type of bearing will cause the motor to come to a standstill' immediately. The motor will draw a heavy current equivalent to the locked rotor current. There is very little change that a relay monitoring the motor current can detect bearing failure of this type before the bearing is destroyed. However, it is essential to disconnect the motor before excessive winding damage. This may be covered in the form of stalling protection.

ii)

Sleeve Bearings

;'' .

Failure of this type of bearing is a very occurrence. If it occurs it will be indicated by rature rise, vibration and increase in motor current in the order ~f 10% to20%.prior. .

13

1I 1

.

.

.

It is generally accepted that the bearing will need replacing following failure, however stall protection will help niinimise damage to the motor itself. Unfortunately, in extreme cases this .is not the case and distortion of the shaft may occur. One method used to prevent this is direct temperature monitoring of the bearings using RTD's for example.

SYNCHRONOUS MOTORS Out-Of-Step Protection

A synchronous motor decelerates and falls out of step when it is subjected to a mechanical overload exceeding its maximum available output. It may also lose synchronism from a fall'in field current or supply voltage. An out-of-step condition will subject the motor to undesirable Overcurrent and pulsating torque leading to eventual stalling. Two methods are available to detect out-of-step condition in a synchronous motor: i)

Field Current Method The alternating component of current induced in the field circuit when the motor falls out of step provides the basis for this method. One arrangement is to connect a reactor in series with the field circuit to divert alternating current to a polarised field-frequency relay, a coil of which is connected i n parallel with the reactor.

Disadvantages : a)

difficult to discriminate between alternating current induced by pole slip and induced by'faults on the supply system or sudden swing of load.

b)

certain faults introduce harmonics, in particular second harmonic alternating cu in the filed circuit.

Power Factor Method

.

This method makes use of the change of power facto that occurs when, the motor poles. When the motor loses synchronism a heavy current at a very low power fac drawn from the supply.

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Protection Against Sudden Restoration Of Supply -.

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On loss of supply a synchronous motor-should be disconnected if the'supply couldbe restoied:;+ automatically or restored without knowledge of the machine operator. This is to .avoid the..$ . ....-...- +, 3 possibility of the supply beingarestoredout of phase with the motor generated emf. ,

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Two ways of detecting loss of supply :

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i)

Overvoltaqe and Underfrequency If the supply busbars have no other load connected and the motor is not loaded the motor,;; terminal voltage could rise instantaneously to 20-30% on loss of supply due to the open ii: circuit regulation of the machine. If the motor is loaded it will decelerate fairly quickly on : .‘, loss of supply and the frequency of terminal voltage will fall.

ii)

Underpower and Reverse Power Applicable when power reversals do not occur under normal operating conditions.

.

.. .

Underpower - arranged to look into the machine; applicable when there is a possibility of no load connected on loss of supply. Reverse power - arranged'to look away from the machine; applicable where there is always load connected. Time delay is required to overcome momentary power reversal due to faults etc.

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Page 14

A C Motor Protection

A. C. Motor Protection .

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There are a wide range of a.c. motors and motor characteristics i n existence, because o f the numerous duties for which they are used. All motors need protection, b u t fortunately, the more fundamental -problems affecting t h e choice of protection are independent o f the type o f motor and the type o f load t o which it is connected. There are some important differences between the protection o f induction motors and synchronous motors, and these are'fully dealt w i t h i n the appropriate section.

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M o t o r characteristics must be carefully considered when applying protection; while this may be regarded as stating the obvious, it is emphasised because it applies more t o motors than t o other items o f power system . . plant. For example, the starting and , s t a l l i n g . - . , .. currents/times must be known when applying.overload. ?':.-.I.-;.--'.,-.: protection, and furthermore the thermal'withstand o f i . . . 1 the machine under, balanced and unbalanced loading -1.' - ' . ++ . must be clearly defined. I ,

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The conditions for which motor protection is required can be divided into t w o broad categories: imposed external conditions and internal faults. Table 19.1 provides details of all likely faults that require protection.

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Extcmal Faults

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Unbalanced rupplics

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Bcating failurcs

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The design of a modern motor protection relay must be adequate t o cater for the protection needs of any one of the vast range of motor designs in service, many of the designs having n o permissible allowance for overloads. A relay offering comprehensive protection will have the following set o f features: a. thermal protection

b. extended start protection c. stalling protection

d. number o f starts limitation

heat a t a rate proportional to temperature rise. This is the principle behind the 'thermal replica' motor used for overload protection.

e. short circuit protection f. earth fault protection

The temperature T a t any instant i s given by:

g. winding RTD measurementltrip

T

h. negative sequence current detection

=

T,,,,,, ( 1 - e-fk)

where:

i. undervoltage protection

T,,,,

= final steady state temperature

s = heating time constant

j. loss-of-load protection

Temperature rise is proportional t o t h e curre

k. out-of-step protection I. loss of supply protection

T=

m. auxiliary supply supervision (items k and I apply t o synchronous motors only) I n addition, relays may offcr options such i s circuit breaker condition monitoring i s a n aid t o maintenance. Manufacturers may 3lso offer relays that implement a reduced functionality t o that given above where less comprehensive protection is warranted [e.g. induction motors o f low rating). The following sections examine each o f the possible failure modes of a motor and discuss h o w protection may be applied t o detect t h a t mode.

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The majority of winding failures are either indirectly or directly caused by overloading [either prolonged or cyclic), operation o n unbalanctd supply voltage, or single phasing, which a l l lead through excessive heating t o the deterioration of t h e winding insulation until an electrical f a u l t occurs. The generally accepted rule is t h a t insulation life is halved for each 10" C rise i n tercperature above the rated value, modified by t h e length of time spent a t the higher temperature. As an electrical machine has a relatively large heat storage capacity, it follows t h a t infrequent overloads of short duration m a y n o t adversely a f f e c t t h e machine. However, sustained overloads o f only 'a' few percent may result i n premature ageing and insulation failure.

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IR = current which, i f flowing continuously, pr temperature T,,,,, i n the motor ~ t , ~ it can ~ ~be fshown ~ ~that, ~ for , any overload 1 , the tirne t for this current to flowis:

t x l o I [ (

should take into account both of these typical equation for the equivalent current being:

lcq = where

-

=

po5irive sequence current

I2

=

negative sequence ,current

,q=

negative sequence rotor resistance positive sequence rotor resistance

at rated spced. A typical value o f K is 3. Finally, the thermal replica model needs t o take i n t o account the iact that the motor will tend t o cool down during periods of light load, and the initial state of the motor. The rllotor will have a cooling time constant, T,. that defines the rate of cooling. Hence, t h e final thermal model can bc expressed as:

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The variety o f motor designs, diverse applications, variety o f possible abnormal operating conditions and resulting modes o f failure result i n a complex thermal relationship. A generic mathematical model t h a t is accurate is therefore impossible t o create. However. i t is possible to develop an approximate model if it is assumed that the m o t o r is a homogeneous body. creating and dissipating .. -,?,.,.; .-,-..

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Furthermore, the thermal withstand capability of the motor is affected by heating i n the winding prior to a It is therefore i m p o r t a n t t h a t t h e relay fault. characteristic takes account o f t h e extremes o f zero and full-load pre-fault current known respectively as the 'Cold' a n d 'Hot' conditions. -

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contain b o t h positive a n d negative'- s components, and both compbnents o f clrrrentgi heating in thr motor. Therefore,. the, the!m

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where:

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10:42

Page 339

-: 9,.{ START!ST,?[.L

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= heating time c o ~ i s t a ~ t t

i a l stare of rr~oror[cold o r /lor) ?la/ setriug c l t r r e n t into account the 'cold' and 'hot' d i n IEC 60255, part 8. -

ays may use a dual slope characteristic for the time and hence values the &time constant are required. Switching between "' values takes place a t a pre-defined motor may. be used to obtain better tripping during starting on motors that use a star~~~i~~ starting,the motor windings cam/ current, while inthe condition, they carry of the current seen by the relay. similarly, I ~e motor is disconnected from the supply, the i;g time constant is set equal to the coolingtime iant TI-

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relay should ideally be matched t o the be capable of close sustained &j a wide range of relay adjustment is . . protection, with good accuracy low thermal +!e

When a motor is started, i t draws a current well i n excess of full load rating throughobt the period that the motor takes to run-up to speed. While the motor starting Ciiiient iedijces somewhat as motor speed increases, i t is normal in protection practice to assume that the motor current remains constant throughout the starting period!. The starting current will vary depending on the design of the motor and method of starting. For motors started DOL (direct-on-line], the nominal starting current can be 4-8 times full-load current. However, when a star-delta

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Should a motor stall whilst running. or fail to start, due to excessive loading, the motor will draw a current equal to its' locked rotor current. It is not therefore possible t o distinguish between a stall condition and a healthy start solely on the basis of the current drawn. Discrimination between the t w o conditions must be made based on the duration of the current drawn. For motors where the starting time is less than the safe stall time o f the motor. protection is easy to arrange.

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A motor may fail to accelerate from rest for a number o f reasons:

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iijelay setting curves are i h o w n i n Figure 19.1. .

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starter is used, the line current will only be 7 / f i o f the

However, where motors are used to drive high inertia loads, the stall withstand time can be less than the starting time. I n these cases, an additional means must be provided to enable discrimination between the t w o conditions to be achieved. --

dd motor

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loss of a supply phase

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mechanical problems

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low supply voltage

19-

excessive load torque etc. A large current will be drawn from the supply, and cause extremely high temperatures to be generated within the motor. This is made worse by the fact that the motor is not rotating, and hence no cooling due to rotation is available. Winding damage will occur very quickly either to the stator or rotor windings depending on the thermal limitations of the particular design (motors are

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said to be stator or rotor limited i n this respect). The method of protection varies depending on whether the starting time is less than or greater than the safe stall time. In both cases, initiation of the start may be sensed by detection of the closure of the switch i n the motor feeder (contactor or CB) and optionally current rising above a starting current threshold value - typically

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20/06/02

10-42

Page 340

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200% o f motor rated current.

For the case of both conditions being sensed, they may have t o occur within a narrow aperture of time for a start to be recognised. .---a,., ~ ~ c L ; arequirements !

may exist for certain types of motors installed i n hazardous areas (e.g. motors with type o f protection EEx 'e') and the setting of the relay must take these into account. Sometimes a permissive interlock for machine pressurisation (on EEx 'p' machines) may be required, and this can be conveniently achieved by use o f a relay digital input and the in-built logic capabilities. .

<

Protection is achieved by use o f a definite time overcurrent characteristic, the current setting being greater than full load current but less than the starting current of the machine. The time setting should be a little longer than the start time, but less than the permitted safe .starting time of the motor. Figure 19.2 illustrates the principle of operation for a successful start.

successful start is used t o select relay timer used for the safe run up time. This time can be longer than the safe stall tjme, as there is both a (small) decrease in current drawn by the motor during the start and the rotor fans

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begin to improve cooling of the machine as i t accelerates. I f a start is sensed by the relay through monitoring current and/or start device closure, but the speed switch does not operate, the relay element uses the safe stall time setting to trip the motor before damage can occur. Figure 19.3(a) illustrates the principle of operation for a successful start. and Figure 19.3(b) for an unsuccessful start.

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Should a motor stall when running or be unable to start? because of excessive load, it will draw a current from t h e i 3 : supply equivalent to the locked rotor current. I t is:3;g; obviously desirable to avoid damage by disconnecting the machine as quickly as possible i f this condition4@$ arises. &,.,,+Y, $

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For this condition, a definite time overcurrent characteristic by itself is not sufficient, since the time delay required is longer than the maximum time that the motor can be allowed to carry starting current safely. An additional means of detection of rotor movement, indicating a safe start, is required. A speed-sensing switch usually provides this function. Detection of a

Motor stalling can be recognised by the motor current:;@$ exceeding the start current threshold after a successful^:$$; start - i.e. a motor start has been detected and the motor:+$?' current has dropped below the start current threshold,::-% within the motor safe start time. A subsequrnt r i a in$ ..,:$ motor current above the motor starting current:i;i?; threshold is then indicative of a stall condition, and,,'@ tripping will occur i f this condition persists for than the setting of the stall timer. An instantaneou~;i$:' .+. J: overcurrent relay element provides protection. :iy,t.?.

-

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In many systems, transient supply voltage loss (typical!Y;$ up to 2 secmdr) does not rerult i n tripping of designate<& motors. They are allowed t o re-accelerate upon@ restoration of the supply. During re-acceleration, the%? .&$

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draw a current similar t o the starting current for a period that may be several seconds. It is thus above the motor stall relay element c u r r e n t threshold. The stall protection would be expected t o operate and defeat the ?bject of the re-acceleration scheme. motor protection relay w i l l therefore recognise the 'resence o f a voltage dip and recovery. and inhibit stall lrotection for a defined period. The undervoltage, 'rotection element (Section 19.11) can be used t o detect he presence o f the voltage dip and i n h i b i t stall 'rotection for a set period after voltage recovery. 'rotection against stalled m o t o r s i n case of a n nsuccessful re-acceleration is therefore maintained. he time delay s e t t i n g is dependent o n the rec~elerationscheme adopted and the characteristics o f ldividual motors. I t should be established after Vforming a transient stability study for the reSeleration scheme proposed.

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Any motor has a restriction on the number of starts that are allowed i n a defined period without the permitted winding, etc. temperatures being exceeded. Starting should be blocked if the permitted number o f starts is exceeded. The situation is complicated b y the fact the number o f permitted 'hot' starts i n a given period is less than the number o f 'cold' starts, due t o the differing initial temperatures o f the motor. The relay must maintain a separate count o f 'cold' and 'hot' starts. By making use o f the data held i n the motor thermal replica, 'hot' and 'cold' starts can be distinguished. To allow the motor t o cool down between starts, a time delay may be specified between consecutive starts (again distinguishing between 'hot' and 'cold' starts). The start inhibit is released after a time determined by the motor specification. The overall protection function is ilhstrated in Figure 19.4.

Cha~ ~ 1 9 - 3 3 6 - 3 5 12 0 / 0 6 / 0 2

10:42

Page 3 4 2

Motor short-circuit protection is often provided t o cater f o r major stator winding faults and terminal flashovers. Because of the relatively greater amount o f insulation between phase windings, faults between phases seldom occur. As the stator windings are completely enclosed in grounded metal, the fault would very quickly involve earth, which would then operate the instantaneous earth fault protection. A single definite time overcurrent relay element is all that is required for this purpose, set to about 125% of motor starting current. The time delay is required t o prevent spurious operation due to CT spill currents, and is typically set at looms. I f the motor is fed from a fused contactor, co-ordination is required with the fuse, and this will probably involve use o f a long time delay for the relay element. Since the object of the protection is to provide rapid fault clearance t o minimise damage caused by the fault, the protection is effectively worthless in these circumstances. It is therefore only provided on motors fed via circuit breakers. Differential (unit) protection may be provided on larger HV motors fed via circuit breakers t o protect against phasephase and phase-earth faults, particularly where the power system is resistance-earthed. Damage to the motor i n case of a fault occurring is minimised, as the differential protection can be made quite sensitive and hence detects faults i n their early stages. The normal definite time overcurrent protection would not be sufficiently sensitive, and sensitive earth fault protection may not be provided. The user may wish t o avoid the detailed calculations required of capacitance current in order to set sensitive non-directional earth fault overcurrent protection correctly on HV systems (Chapter 9) or there may be no provision for a VT to allow application of directional sensitive earth fault protection. here is still a lower limit to the setting that can be applied, due to spill currents from CT saturation during starting. while on some motors. neutral current has been found t o flow during starting. even with balanced supply voltages. that would cause the differential protection to operate. For details on the application of differential protection, refer to Chapter 10. However, non-directional earth fault overcurrent protection will normally be cheaper i n cases where adequate sensitivity can be provided.

One o f the most common faults t o occur on a motor is a stator winding fault. Whatever the initial form of the fault (phase-phase, etc.) or the cause (cyclic overheating, etc.), the presence of the surrounding metallic frame and casing will ensure that i t rapidly develops into a fault involving earth. Therefore. provision of earth fault protection is very important. The type andscnsitivity of protection provided depeAds largely' on the system earthing, so the various types will be dealt with i n turn.

I t is common, however, t o provide both instantaneous and time-delayed relay elements t o cater for major and ,:,slowly developing faults. ..:$ .;d '%xi

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Most LV systems fall into this category, for reasons of personnel safety. Two types o f earth fault protection are commonly found - depending on the sensitivity required. For applications where a sensitivity of > 20% of motor continuous rated current is acceptable, conventional earth fault protection using the residual CT connection of Figure 19.5 can be used. A lower limit is imposed on the setting by possible load unbalance and/or (for HV systems) system capacitive currents. .

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Care must be taken to ensure that the relay does not operate from the spill current resulting from unequal CT saturation during motor starting, where the high currents involved will almost certainly saturate the motor CT's. I t is common to use a stabilising resistor i n series with the relay, with the value being calculated using the formula:

.r.-..

where:

I,, = starting current referred t o CT secondary I,, = relay earth fault setting (A) Rslah = stabilising resistor value (ohms] = d.c. resistance of CT secondary (ohms) R, = CT single lead rcstistance (ohms) RI

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CT connection factor L

1 for star p t at CT

2 for star p t a t relay) relay input restistance (ohms) ffect of the stabilising resistor is t o increase the ive setting of the relay under these conditions, and delay tripping. When a stabilising resistor is used, tripping characteristic should normally be ntaneous. An alternative technique, avoiding the use stabilising resistor is to use a definite time delay cteristic. The time delay used will normally have to und by trial and error, as it must be long enough to ent maloperation during a motor start, but short gh t o provide effective protection i n case o f afault.

If a more sensitive relay setting is required, it is necessav t o use a core-balance CT. This is a ring type CT. through which all phases o f the supply t o the motor are passed, plus the neutral on a four-wire system. The turns ratio o f the CT is no longer related to the normal line current expected t o flow, so can be chosen t o optimise the pickup current required. Magnetising current requirements are also reduced, with only a single CT core to be magnetised instead of three, thus enabling low settings to be used. Figure 19.7 illustrates the application o f a core-balance CT, including the routing of the cable sheath t o ensure correct operation in case o f core-sheath cable faults.

m,

rdination with other devices must also be considered.

Cablc b o x .

Cablc gland /sheath g r o u n d connection

low the maximum system fault current - reliance is b c e d on the fuse ir, these circumstances. As a trip command from the reiay instructs the contactor t o open. &re must be taken t o ensure that this does not occur until the fuse has had time to operate. Figure 19.6(a] illustrates '$correct grading of i h e relay with the fuse, the relay k r a t i n g first for a range of fault currents in excess of the nntactor breaking capacity. Figure 19.6(b) illustrates &ect grading. To achieve th~s,i t may require the use o f ;liintentional definite :ime delay in The relay.

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These are commonly found on HV systems, where the intention is to limit damage caused by earth faults through limiting the earth fault current that can flow. Two methods of resistance earthing are commonly used:

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In this method, the value of resistance is chosen to limit the fault current to a few hundred amps - values of ~ O O A - ~ O Obeing A typical. With a residual connection of line crs, the senjjliviti; pos;i';le is about !no/, of CT rated primary current, due to the possibility of CT saturation during starting. For a core-balance CT, the

,

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sensitivity that is possible using a simple non-directional earth fault relay element is limited to three times the .:$ steady-state charging current of the feeder. The setting i j shoild not be greater than about 30% of the minimum 'i earth fault current expected. Other than this, t h e <,-. considerations in respect of settings and time delays arc as for solidly earthed systems.

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applying earth faults a t various parts of the system and measuring the resulting residual currents.

R O g m e HV systems, high resistance earthing is used t o &rt the earth fault current t o a f e w amps. I n this case, S;c system capacitive charging current will normally &vent conventional sensitive earth fault protection &ng applied, as the magnitude of the charging current ill be comparable w i t h the earth fault current i n the of a fault. The solution is t o use a sensitive ircctional earth fault relay. A core balance CT isused in rnjunction w i t h a VT measuring the residual voltage of he system, with a relay characteristic angle setting o f 45' [see Chapter 9 for details). The VT must be suitable the relay and therefore the relay manufacturer should :consulted over suitable types - some relays require )at the VT must be able t o carry residual flux and this lies out use-of a 3-limb. 3-phase VT. F,. setting o f 125% f the single phase capacitive charging current for the hole system is possible usins this method. The time :lay used is not critical but must be fast enough to sconnect equipment rapidly in the event o f a second ~ r t hfault occurring immediately after the first. 'inimal damage is caused by the first fault, b u t the ,cond effectively removes the current l i m i t i n g sistance from the fault path leading to very large fault !rrents.

If it is possible t o set the relay to a value between the charging current on the feeder being protected and the charging current for the rest o f the system, the directional facility is not required and the VT can be dispensed with. The comments made in earlier sections on grading with fused contactors also apply.

1 alternative

technique using residual voltage detection also posible, and is described in the next section.

rth fault detection presents problems on these systems Ice no earth fault current flows for a single earth fault. lwever, detection is still essential as overvoltages occur sound phases and i t is necessary to locate and clear t fault before a second occurs. Two methods are ssible, detection of the resulting unbalance in system arging currents and residual overvoltage.

A single earth fault results in a rise in the voltage between system neutral and earth, which may be detected by a relay measuring the residual voltage of the system (normally zero for a perfectly balanced, healthy system]. Thus, no CT's are required, and the technique may be useful where provision of an extensive number of core-balance CTs is impossible or difficult, due to physical constraints or on cost grounds. The VTs used must be suitable for the duty, thus 3-limb, 3-phase VTs are not suitable, and the relay usually has alarm and trip settings, each with adjustable time delays. The setting voltage must be calculated from knowledge of system earthing and impedances, an example for a resistanceearthed system is shown in Figure 19.10.

nsitive earth fault protection using a core-balance CT -equired for this scheme. The principle is that detailed Section 9.16.2, except that the voltage is phase shifted +go' instead of -90'. To illustrate this, Figure 19.8 )WS the current distribution i n an Insulated system ljected to a C-phase t o earth fault and Figure 19.9 the ay vector diagram for this condition. The residual -rent detected by the relay is the sum of the charging 'rents flowing in the healthy part of the system plus healthy phase charging currents on the faulted der - i.e. three times the per phase charging current the healthy part of the system. A relay setting of 30% this value can be used to provide protection without : risk of a trip due to healthy system capacitive ~ r g i n gcurrents. As there is no earth fault current, it is o possible to set the relay at site after deliberately -

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Grading of the relays must be carried out with care, as the residual voltage will be detected by all relays in the affected section of the system. Grading has to be carried out with this in mind, and will generally be on a time basis for providing alarms (1" stage), with a high set definite time trip second stage to provide backup.

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tor positive sequence impedance at slip s

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Modern motor protection relays have a negative sequence current measurement capability, i n order to. provide such prote~tion. The level of negative sequence unbalance depends largely upon the type of fault. For loss of a single phase at start, the negative sequence current will be 50010 of the normal starting current. It is more diff~cult to provide an estimate of the negative sequence current i f loss of a phase occurs while running. This is because the impact on the motor may vary widely, from increased heating t o stalling due t o the reduced torque available.

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rr: A typical setting for negative sequence current o protection must take into account the fact that the motor circuit protected by the relay may not be the f!:.:' :..; ?ource of the negative 5equence current. Time s h ~ u \ d b e =% . : allowed for the appropriate protection to clear -the .: 1: source of the negative sequence current without ; introducing risk of overheating to the motor being considered. This indicates a two stage tripping o % characteristic, similar i n principle t o overcurrent < protection. A low-set definite time-delay element can be used to provide an alarm, with an IDMT element used to trip the motor in the case of higher levels of negative seq"ence current, such as loss-of-phase conditions at start, occurring. Typical settings might be 20% o f CT ' 19 ' rated primary current for the definite time element and 50010 for the IDMT element. The IDMT time delay has to be chosen to protect.the motor while, if possible, grading negative sequence relays on the system. s may not incorporate two ekments, i n which ingle element should be set to protect the motor, with grading being a secondary consideration.

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Negative sequence current is a t twice supply frequency. Skin effect in the rotor means that the heating effect i n the rotor of a given negative sequence current is larger than the same positive sequence current. Thus, negative sequence current may result in rapid heating o f the motor. Larger motors are more susceptible i n this respect, as the rotor resistance of such machines tends t o be higher. Protection against negative sequence currents is therefore essential.

indicates negative sequence quantities

R , + R;

. .

F o r the same motor, negative sequence voltages i n excess of 17% will result i n a negative sequence current larger than rated f u l l load

standstill (s=1.0), impedance

11

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....

' leading to' excessive heating.

suffix p indicates positive sequence quantities

suffix

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speed is approximately equal t o the positive sequence reactance at standstill. An alternative more meaningful way of expressing this is:

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positive seq. impedance negative seq. impedance

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starting current rated current

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On wound rotor machines, some degree of protection ,..c,:.;~ p;.!:$>.j2;?'...;:,>:: ,.+?: against faults i n the rotor winding can be given by an instantaneous stator current overcurrent relay element. As the starting current is normally limited by resistance '- 1 p. ~+P",P". to a maximum of twice full load, the instantaneous unit , . ~-:!~' can safely be set to about three times full load if a slight :,:!'6~!T!. , . . ..,.. . .. I . 4':;:.;;:;:,.;:, <.

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and i t is noted that a typical LV motor starting current is GxFLC. Therefore, a 50j0 negative sequence voltage (due to, say, unbalanced loads on the system) would produce a 30010 negative sequence current in the machine,

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;.?*+\.V": :br,kgat i m e delay o f approximately 3 0 milliseconds is :;;.. +$:$.:&$.

-..,..++.z; incorporated. It should be noted that faults occurring i n : ;.3:::*&:$ ; :. .c ~ ~ ., y,~.~ : : .t hi e rotor windinq would n o t be detected b y any :::;$e:::.: . . d~fferentialprotection applied t o the stator. ;$;:?*;!@*->

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RTD's are used t o measure temperatures o f motor windings or shaft bearings. A rise i n temperature may denote overloading o f the machine, or the beginning of a fault i n the affected part. A motor protection relay will therefore usually have the capability of accepting a number of RTD inputs and internal logic t o initiate an alarm and/or trip when the temperature exceeds the appropriate setpoint(s). Occasionally, HV motors are fed via a unit transformer. and i n the;e circumstances, some o f the motor protection relay RTD in.puts may be assigned t o the transformer winding temperature RTD's. thus providing overtemperature protection for the transformer without the use o f a separate relay.

factors in mind.

failure i n a mechanical transmission (e.g. conveyor belt), or i t can be used with synchronous motors t o protect,

There are t w o types o f bearings to be considered: the anti-friction bearing (ball or roller), used mainly on small .. 'a. .:.. ,.' . motors (up to,.around 3 5 0 k ~ ) ,and the sleeve bearing. . .a. L . ,..?.. .. -used mainly on large motors:

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The failure of ball or roller bearings usually occurs very quickly, causing the motor t o come to a standstill as pieces of the damaged roller get entangled with the others. There is therefore very little chance that any relay operating from the input current can detect Searing failures of this type before the bearing is completely destroyed. Therefore, protection is limited to disconnecting the stalled m o t o r rapidly to avoid consequential damage. Refer t o Section 19.2 on stall protection for details of suitable protection.

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maloperation.

This is especially important for system transients. synchronous motor loss-of supply protection.

Failure of a sleeve bearing can be detected by means of

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itself but will operate to protect the motor from excessive damage. Use of RTD temperature detection, as noted i n Section 19.9, can provide suitable protection. allowing investigation into the cause of the bearing running hot prior t o complete-failure.

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Motors may stall when subjected t o prolonged undervo!tage conditions. Transient undervoltages will generally allow a motor to recover when the voltage is

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6-351

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ied voltage to stator or field windings. Such a fall n o t need to be prolonged, a voltage dip o f a few nds may be all that is required. An out-of-step ition causes the motor to draw excessive current generate a pulsating torque. Even if the cause is oved promptly, the motor will probably not recover chronism, but eventually stall. Hence, it must be m&iinecird from the supply. &.

i q e current drawn during an out-of-step condition is a t 5 v e r y low power factor. Hence a' relay element that b o n d s t o low power factor can be used to provide - The element must be inhibited during rting, when a similar low power factor condition rs. This can conveniently be achieved by use of a !&finite time delay, set t o a value slightly i n excess of the k. otor start time.

A low forward power relay can detect this condition. SeeSection 19.12 for details. A time delay will be required to prevent operation during system transients leading t o momentary reverse power flow i n the motor. ..

-

19.14- MOTOR PROTECTION E X A M P L E S This section gives examples o f the protection o f HV and LV induction motors.

Table 19.2 gives relevant parameters of a HV induction motor to be protected. Using a MiCOM P241 motor protection relay, the important protection settings are calculated i n the following sections.

g

n e power factor setting will vary depending on the rated tpwer factor of the motor. It would typically be 0.1 less fh& the motor rated power factor i.e. for a motor rated at 0.85 power factor, the setting would be 0.75. .

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If the supply to a synchronous motor is interrupted, it a essential that the motor breaker be tripped as quickly 3s possible if there IS any possibil~tyo f the supply 3eing restored automatically or without the machine ~perator'sknowledge.

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his is necessary in order t o prevent the supply being estored out of phase with the motor generated voltage. 'WO

methods are generally used to d'etect this condition, to cover different operating modes of the motor.

Iorder

he underfrequencv relay element will operate i n the ase of the supply failing when the motor is on load, !hich causes the motor to decelerate quickly. Typically, NO elements are provided, for alarm and trip ldications. i e underfrequency setting value needs to consider the Iwer system characteristics. In some power systems. ngthy periods of operation at frequencies substantially :low normal occur, and should not result in a motor ip. The minimum safe operating frequency of the otor under load conditions must therefore be :termined, along with minimum system frequency.

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.

The current setting IT" is set equal to the motor full load current, as it is a CMR rated motor. Motor full load current can be calculated as 211A, therefore (in secondary quantities):

-19.

Use a value of 0.85, nearest available setting The relay has a parameter, K, to allow for the increased heating effect of negative sequence currents. In the absence of any specific information, use K=3. Two thermal heating time constants are provided, r , and - . : : r,. r, is used for starting methods other than DOL, . . ,.. . otherwise it is set equal to r,. r , is set to the heating ,-.,j.::,..: .:.::: time constant, hence r,=r2=25mins. Cooling time :::' :?'.!f.?$::. , \,p:,'. :. :-j-.' "" constant r, is set as a multiple'of r,. With a cooling time $.:c;::; .... -!.";.:,;:.G>y. :, constant of 75mins, .,, . \-. - .,. ..... ,

is can be applied i n conjunction w i t h a time delay to feet a loss-of-supply condition when the motor may

are a busbar with other loads. The motor may attcmpt supply the othcr loads with power from the stored letic energy of rotation.

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condition at starting. 19.1.I..? Ptotcctioti of

In accordance with Section 19.7, use a ~ e t t i n go f

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/02

Page351

10:46

where

b e carefully co-ordinated w i t h the fuse re t h a t t h e contactor does n o t attempt t o break a i n excess of i t s rating. Table 19.3(a) gives details LV m o t o r and associated fused contactor. A M P 2 l l m o t o r protection relay i s used t o provide

I,, = motor rated primary current Ip = CT primary current Hence, I b = 5 x 1 3 2 / 1 5 0 = 4.4A W i t h a motor starting current o f 670% o f nominal, a setting o f the relay thermal t i m e constant w i t h motor initial thermal state o f 5.9% o f 15s is found satisfactory, as shown i n Figure 19.14.

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A

250 (a1 LV motor cxamplc data

setting M r l o a d tirnc dclay &niaIaIK:c

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15

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Re relay is set i n secondary quantities, and therefore a hitable CT r a t i o has t o be calculated. From the relay i a n u a l , a CT w i t h 5A secondary rating and a motor rated :urrent i n the range of 4-6.4 when referred t o the secondary of CT is required. Use o f a 15015A CT gives a notor rated cuirent o f 4.4A when referred t o -the CT iecondary, so use this CT ratio.

h e fuse provides the motor overcurrent protection, as the Irotection relay cannot be allowed t o trip the contactor on Wrcurrent in case the current to be broken exceeds the mntactor breaking capacity. The facility for overcurrent jrotection within the relay is therefore disabled. 1:; r - . . - . . . . . . . . . . .. . . . . The m o t o r is an existing one, and no data exists for it x c e p t the standard data provided i n the manufacturers :atalogue. This data does n o t include the thermal heating) time constant o f the motor. n these circumstances, it is usual t o set the thermal jrotection so t h a t it lies just above the motor starting :Went. ;he current setting o f the relay, Ib , is found using the orm mu la

Ib

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6

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I//, [b] Rclay trip c h a r a c l c ~ ~ ~ t i c

The motor is built t o IEC standards, which permit a negative sequence (unbalance) voltage of 1% on a continuous basis. This would lead t o approximately 7010 negative sequence current-in the motor (Section 19.7). As the relay is fitted only w i t h a definite time relay element,a setting of 200,~ (from Section 19.7) is appropriate, w i t h a tirnedelay of 2 s s to allowfor short high-level negativesequence transients arising from other causes. ...

The relay has a separate element f o r this protection. Loss of a phase gives rise t o large negative sequence currents, and therefore a much shorter t i m e delay is required. A definite time delay o f 5s is considered appropriate. The relay settings are summarised i n Table 19.3(b).

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Motor Protection Setting Criteria and Tutorials Page 1 of 38

MOTOR PROTECTION IETTING CRITERIA

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Motor Details :

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by.

-

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M ~ t o Rating r iri KW

.-

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Rated Voltage in KV

-

Motor Application

:

Others

Motor Control by ( Contactor / Circuit Breaker ) Motor Full Load current -: -

,:I:

- ' '

CB 230 Amps

CT Ratio

300/1 A

Type of Motor Starting

DOL

Starting current in Primary Arnps ( 100 % Voltage )

1 380

Starting current in Primary Amps ( 80 % Voltage )

1104

Moto~' Starting time in seconds ( 100 % Voltage )

5

Motor Starting time in seconds ( 80 % Voltage )

8

Thermal overload characteristics ( Available/ not-available) Stalling current in primary Amps

Available 1380

Hot stall withstand time in seconds

20

Cold stall withstand time in seconds

30

-

-

-

-

OALSTOM Limited, fnergy Automation & Information

6


Motor Protection Settins Crie and Tutofi, Page 2

G

Thermal Overload characteristic Curves

Times full load current X 1.4 X 2.0

Cold Characteristics 4000 750

Hot Characteristics 2700 500

X 4.0 X 5.0 X Stalling current

85 48 30

57 30 20

.

OALSTOM Limited, Energy Automation & information

.


.

Motor Protection Setting Criteria

Calculations Thermal Overload Protection:

Set the pick-LIPat 103% of the rated current = 230 x 1.03 = 236.9 Amps ~eferred to secondary = 0..789 = 0.78 Set Is = 0.78 Calculation for the time constant at overload levels ( 1
The operating time for the thermal overload characteristic available in the relay is as follows : t = T x In { ( PSM2)/( PSM2- 1 ) ''

. ...... . .

. .

. .

Therefore the required time constant can be calculated as : T = t / { In { ( PSM2)/( PSM2 - 1)))

At 1.4 time rated current -

For Cold Curve PSM = 1.411.03 = 1.36, we require a operating time of 4000 x 0.7= 2800 ( 30 % margin ) T T

= t / { In { ( PSM2)/( PSM2 - 1 ))) = 2800 / { In { ( 1.362)/( 1.362 - I ) ) ) = 3599 Seconds = 59.98 min

Calculation for the time constant at overload levels ( leq > 2) times the pic k-up current At 2 time rated current the relay curve is adiabatic.

we require an ope;ating time of 750 x 0.7= 525 ( 30 % margin )

OALSTOM Limited, Enemy Automation & Information

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(2)2x 525 = (1.03)2 XT r = 1979.45 sec = 32.99 min

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At 3 time rated current

dperating time of 190 x 0.7= 133 ( 30 % margin )

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(3)2x 133 = (1.03)2 xr r = 1128 sec = 18 min

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The minimum value of the time constant is considered. So the time constant considered in this case is 18min

j:.?

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Based on the above setting, the hot curve based on the Hot to Cold R ~ I .. .$ setting can be calculated as follows. For Hot curve

Select HCR ( hot to cold Ratio ) = 0.66

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For 1.4 times Full load Current time of operalion :

t = { r x In { ( PSM2)/( PSM2- 1 ) ) x 0.66 = (18 x In ( 1.362)/(1.362- 1 ) ) x 0.66 = 9.24 min = 554.4 seconds For 2 times Full load Current time of operation :

For 3 times Full load Current time of operation :

-


I.

59,

ked Industrial Power System >n

Motor Protection Setting Criteria and Tutorials Page 5 of 38

pmparing the above values with the hot withstand characteristic of the &tor, we find that the safety margin between relay curve and the motor h e is clearly more than 30 %.

;"ce the following settings are recommended ermal Pick-up current IS = 0.78 ne constant TH = 18 minutes HCR = 0.66 ling time constant = 5 x Is ( normally adopted, if data Tc I<

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available )

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Motor Protection Setting c&&$ and Tutorials': Page 6 of a -

Start Protection Maximum Motor starting current at rated voltage

.-

6 Times Full load Current

1 380 Amps

-

Maximum ~ o t o starting r current at lower voltage of say 80%

-

80% of max starting curent

1 104 Amps

Prolonged Start Proteclion : This protection will operate if the motor takes longer time to start. The setting will b e based on the worst case type of voltage for starting, which occurs when starting with low voltage Therefore Current setting will be 80% of Max current during starting at low voltage -

IS, = 0.8 x 0.8 x 1380 / 300= 0.78 Set IS{- = 3.76

3.76

Time Setting will determine after how much time with this current will the relay detect it as a prolonged start. This requires the value of the maximum starting time, which is applicable, when the motor starts with low voltage. Is, = 8 + 4 seconds ( margin) = 12 seconds

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lvanced Industrial Power System otection

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Motor Protection Settit?=Criteria and Tutorials Page 7 of 38

of start limita.lions

!&' Number of Cold starts per hour Set = 3 as motor is rated for 4 starts per hour Number of Hot starts per hour Set = 1 as motor is rated for 2 starts per hour This setting can be changed depending on how frequently we use the Phase Sequence Startinq d i..i

As the motor most probably will be unidirectional, it is generally advised to enable Reverse Phase sequence protection.

Set RPS as enabled

-


Mvancsc! !ndustrial Power System Protection

Motor Protection Setting Cfie* and Tutoriak Page 6 of

s

Siait Protection Maximum Motor starting current at rated voltage

-

6 Times Full load Current

1380 Ar;ips

Maximum Motor starting currenl at lower voltage of say 80%

-

80% of max starting curent

1 104 Amps

Prolonged Start Protection : This protection will operate if the motor takes longer time to start. The setting will be based on the worst case type of voltage for starting, which occurs when starting with low voltage. Therefore Current setting will be 80% of Max current during starting at low voltage -

Isi = 0.8 x 0.8 x 1380 / 300=

3.76

0.78 Set 1st- = 3.76 Time Setting will determine after how much time with this current will the relay detect it as a prolonged start. This requires the value of the maximum starting time, which is applicable, when the motor starts with low voltage. 1st = 8 + 4 seconds ( margin) = 12 seconds


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Motor Protection Settinz Criteria and~utoriais Page 7 of 38

Number of start limitations 6 B

i Number of Cold starts per hour Set = 3 as motor i s rated for 4 starts per

;hour

,I: Number of Hot starts per hour Set = 1 as motor is rated for 2 starts per hour ''

This setting can be changed depending on how frequently we use the

li-Zeverse Phase Sequence Startinq v. !:-

F 1'

As the motor most probably will be unidirectional, it is generally advised to enable Reverse Phase sequence protection. Set RPS as enabled

-

OALSTOM Limited, Energy Automation & !nformation

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Motor Protection Setting Criie and Tutorial Page 1 0 of S

-

Ne~ativePhase Sequence: The negative phase sequence protection has to be graded with the NPS withstand levels of the motor. In absence of this, it is recommended to provide current setting equal to rated current. Set current setting

-

1 .oo

Time characteristic-setting may be set to-definitetime as we de do not have the inverse withstand level of motor. The definite time setting can be set to 0.1 sec. This means that i f the negative sequence settings reaches rated current, the relay will operate instantaneously.


OALSTOM Limited, Energy Automation & Information *

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Advanced Industrial Power. System . Protection ,

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Motor Protection Setting Critei and Tutori~ Page 10 of I

'

-

Negative Phase Sequence: The negative phase sequence protection has to be graded with the NPS withstand levels of the motor. In absence of this, it is recommended to provide current-settingequal to rated current. Set current setting

-

1 .oo

Time characteristic .setting may be set to defiriite time as we de do not have the inverse withstand level of motor. The definite time setting can be set to 0.1 sec. This means that if the negative sequence settings reaches rated current, the relay will operate instantaneously. -

OALSTOM Limited, Energy Awtomation & Information

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.Motor Proiection Setting Criteria and Tutorials Page 1 1 of 38

ault setting shall be based on the standing leakage currents ethod of system earthing. If the system is'resistance earthed, be required and the required primary operating current may based on system study. ent case is assumed to be on a system which is solidly earthed, balance leakage currents can be measured using standard de of connection and earth fault setting shall be made . Generally the leakage currents shall not exceed 5 % of the t. Therefore the current setting may be set to 10%of the rated -

Current setting

0.1 x full load Current x CTsec x1000 CTpri

-

0.1-x230 x 1 x 1000 300 =

76.67

-

Set lo = 80mA Time delay setting may be set to instantaneous which will be 0.1 sec ( 100mA ) . This is an intentional delay and is used to prevent inrush currents, which last for couple of cycles from operating the e/f element during

-.


I

-.

Advanced Industrial Power System

Negative Phase Sequence:

provide current setting equal to rated current. Set current setting

-

1 -00

Time characteristic-setting may be set to definite time as we de do not have the inverse withstand level of motor.

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The definite time setting can be set to 0.1 sec.

.

,,\ ,,$! .4b, * .I.$ :.a>

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This means that if the negative sequence settings reaches rated current, the relay will operate instantaneously. -

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-Motor Prokction Setting Criteria and Tutorials Page 1 1 of 38

Earth Fault Protection: P"

-

\_ 1

'The earth fault setling shall be based on the standing leakage currents and the method of system earthing. If the system is resistance earthed, CBCT may be required and the required primary operating current may be studied based on system study.

c-

I

I

As this present case is assumed to be on a system which is solidly earthed, standing unbalance leakage currents can be measured using standard residual mode of connection and earth fault setting shall be made accordingly. Generally the leakage currents shall not exceed 5 % of the rated current. Therefore the current setting may be set to 10%of the rated current. -

Current setting

0.1 x full load Current x CTsec x1000 CTpri

-

Set lo = 80mA Time delay setting may be set to instantaneous which will be 0.1 sec ( 100mA ) . This is an intentional delay and is used t o prevent inrush currents, which last for couple of cycles from operating the e/f element during starting.


Notes 1 C T S

URRENT TRANSFORMERS - STEADY STATE BEHAVIOGR

!g

'-';Current h n s f o r m e r s are among the most commonly used items of electrical apparatus and yet, "~surprisingly,there seems to be a general lack of even the most elementary knowledge -2*. $'concerning their characteristics, performance and limitations among those engineers who are $,continually using them. The importance of current transformers in the transmission and :&distribution of electrical energy cannot be over emphasised because it is upon the efficiency of +<. Ecurrent transformers, and the associated voltage transformers, th& the accurst=: metering and " effective protection of those distribution circuits and plant depend. -

Current and voltage transformers insulate the secondary (relay, instrument and meter) circuits from primary (power) circuit and provide quantities in the secondary which are proportional to those in the primary. The role of a current transformer in protective relaying is not as readily defined as that for metering and instrumentation. Whereas the essential role of a measuring transformer is to deliver from its secondary winding a quantity accurately representative of that which is applied to the primary side, a protective transformer varies in its role according to the type of protective gear it serves. . Failure of a protective system to perform its function correctly is often due to incorrect selection

of the associated current transformer. Hence, current and voltage transformers must be regarded as constituting part of the protective system and carefully matched with the relays to fulfil the esseqtial requirements of the protection system. There are two basic groups of current transformer, the requirements of which are often radically different. It is true in some cases the same transformer may serve both purposes but in modern practice this is the exception rather than the rule: 1. Measurement CT's - The measuring current transformer is required to retain a specified accuracy over the normal range of load currents. 2. Protection CT's - The protective current transformer must be capable of providing an adequate output over a wide range of fault conditions, from a fraction of full load to many times full load. Therefore they generally have different characteristics.

CURRENT TRANSFORMER STANDARDS Various international standards are available. Such standards give information on the classification, selection, error and operation of current transformers. They are a valuable source of reference and can be used in conjunction with the relay manufacturer guide when selecting the appropriate CT. The list below gives some examples: IEC

'

EUROPEAN

8RI-rISH AMERICAN CANADIAN AUSTRALIAN

'

IEC 185.1987 IEC 44-6:1992 IEC 186.1987 BS 7625 BS 7626 BS 7628 BS 3938:1973 BS 3941 :1975 ANSI C51.13.1978 CSA CAN3-C13-M83 AS 1675-1986

CTs CTs vrs vrs CTs CT+VT CTs vrs CTs and VTs CTs and VTs CTs

Page 1

.

.

-.

.

.

.

,

. ..

Please note that the above are the applicable standards at the ti,me of print of this document an' therefore they may vary.

:* .?.s. . ....:...

CURRENT TRANSFORMER CONSTRUCTION

+,;c

. .

7

A current transformer consists essentially of an iron core with two windings. One winding is connected in the circuit whose current is to be measured and is called the primary and the other winding is connected to burden, and called the secondary. Two of the most basic construction of current transformers are the bar type and wound type: 1. Bar Type - Sometimes referred to as 'Bushing Type'. Such current transformers normally have a single concentrically placed primary conductor, sometimes permanently built into the. CT and provided with the necessary primary insulation, but very often the bushing of a circuit breaker or power transformer. At low primary current ratings it may be difficult to obtain ~ufficientoutput at the desired accuracy because a large core section is needed to provide enough flux to induce the secondary emf in the small number of turns.

'

PRIMARY

DARY

2. Wound Type -With this device it is possible to change the number of primary turns, thus increasing the CT output voltage with altering the turns ratio. Therefore, for the same output the wound CT is smaller in CSA than the bar type.

Page 2

I

TENT TRANSFORMER POLARITY : is

no official standard when it comes to defining the polarity of current transformers. ver, most Engineers will use P I and P2 to define the primary winding and S1 and S2 to the secondary winding. Generally speaking when P1 goes high S1 goes high. Therefore current flows from P1 to P2 it is transferred and flows through the external circuit from S1 Typically P2lS2 is towards the Item of plant being protected.

{ENT TRANSFORMER THEORY

3w current in the primary winding produces an alternating flux in the core and this flux 2s an e.m.f. in the secondary winding which results in the flow of secondary current when ~ndingis connected to an external closed circuit. -The magnetic effect of the secondary ~ t in , accordance with fundamental principles, is in opposition to that of the primary and the of the secondary current automatically adjusts itself to such a value, that the resultant 2tic effect of the primary and secondary currents, produces a flux required to induce the necessary to drive the secondary current through the impedance of the secondary. In an ransformer, the primary ampere-turns are always exactly equal to the secondary ampereand the secondary current is, therefore, always proportional to the primary current. In an current transformer, however, this is never the case. All core materials, so far discovered, e a certain number of ampere-turns to induce the magnetic flux required to induce the sary voltage. lost accurate current transformer is one in which the exciting ampere-turns are least in rtion to the secondary ampere-turns. Exciting ampere-turns may be reduced in three ~ l ways: e By improving the quality of the magnetic material Cold rolled grain oriented silicon steel (C.R.O.S.S.) has a magnetisation characteristic with a knee point at 1.6 tesla.

.

. ,, ,

.

.4! , .

,.

....I

Nickel steel (Proprietary name Mumetal) has a knee point of 0.7 tesla.

:! . . . ,

..

:,t.,

,I

.

,

By decreasing the mean magnetic path of the core.

.C

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.,

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. :! . 2. : ."; Q:. ./

>,

:7:;

.<

By reducing the flux density in the core.

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CURRENT TRANSFORMERS BASIC FORMULAE

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..... ...,. Protective relays are designed to operate from secondary quantities supplied from current transformers and from voltage (or potential) transformers. The secondary output of these devices is the information used by the relays to determine the conditions existing in the plan > being protected. It is necessary, therefore, that the secondary output of current and voltage ? present a true picture to the relays of the conditions in the primary circuit during faults as well as -,. during normal loads. Or, alternatively, that their performance be known under extreme conditions so that any error in reproduction in the secondary circuit can be partially or completely compensated for in the setting and characteristics of the relay.

.

In many applications, core saturation will .almost inevitably occur during the transient phase of a heavy short circuit. The performance of the associated instrument transformers during faults is, therefore, an important consideration in providing an effective relaying scheme. The relays and their associated current transformers must be considered as a unit in determining the overall performance of the protective scheme. Consequently, the characteristic of the current and potential transformers at high currents and low voltage respectively, must be known. In any current transformer the first consideration is the highest secondary winding voltage possible prior to core saturation. This may be calculated from : Ek = 4.44 x B A f N volts Where : Ek = secondary induced volts (rms value, known as the knee-point voltage) N = number of secondary turns f = system frequency in hertz A = net core cross-sectional area in square meters. This induced voltage causes the maximum current to flow through the external burden whilst still maintaining a virtually sinusoidal secondary current. Any higher value of primary current demanding further increase in secondary current would, due to core saturation, tend to produce a distorted secondary current. The relevant circuit voltage required is typically : Equation 1 Where : Is ZB ZS ZL

= secondary current of ct in amps (assume nominal value, usually 1A or 5A) = the connected external burden in ohms = the ct secondary winding impedance in ohms = the resistance of any associated connecting leads

In any given case, several of these quantities are known or can usually be estimated in order to predict the performance of the transformers. From the ac magnetisation characteristic, commonly plotted in secondary volts versus exciting current, Es can be determined for a minimum exciting current. The equation for the relevant circuit voltage given above then indicates whether the voltage required is adequate.

Page 4

-

--

at a bar primary type 200015A (CROSS core) current transformer having a core csa square cm's is available with a secondary resistance of 0.31 ohm. The maximum to which the transformer must maintain its current ratio is 40,000 amperes. It is k:required to determine the maximum secondary burden permissible if core saturation is to be P' Assume that the current transformer core will start to saturate at 1.6 tesla. )

:

P r From the data given :

N = f

2000/5 = 400 turns

= 50 H z .

Secondary current (Is) with a primary current of 40,000A is given by

Knee point voltage Ek is-given as follows :

= 284 volts Maximum burden permissible (including ct secondary resistance and lead burden) is equal to = 2 84 ohms 284 / 100 Consequently, the connected burden including that of the p~lotscan be as high as 2.84 - 0.31 = 2 -53 ohms for negligible saturation in the core. Thus it mav be seen that the secondary burden and the maximum available fault current are two important criteria in determining the performance of a given current transformer. A current transformer may operate satisfactorily : a)

At a high primary current where the connected secondary burden is low

b)

At a lower primary current where the secondary burden IS high

CURRENT TRANSFORMER MAGNETISATION CURVE

..

'The primary current contains two components. These are respectively the secondary current which is transformed in the inverse ratio of the turns ratio and an exciting current, which supplies the eddy and hysteresis losses and magnetises the core. This latter current flows in the primary winding only and therefore, is the cause of the transformer errors. It is, therefore, not sufficient to assume a value of secondary current and to work backwards to determine the value of primary current by invoking the constant ampere-turns rule, since this approach does not take into account the exciting current. From this observation it may be concluded that certain values of secondary current could never be produced whatever the value of primary current and this is of course, the case when the core saturates and a disproportionate amount of primary current is required to magnetise the core.

, ,;.

- ..C<,

The amount of exciting current drawn by a current transformer depends upon the core m and the amount of flux which must be developed in the core to satisfy the burden require the current transformer. The appropriate current may be obtained directly from the exciting characteristic of the transformer since the secondary e.m.f. and therefore the flux develope proportional to the product of secondary current and burden impedance. -

The general shape of the exciting characteristic for a typicai yrade of CRZSS (cold rol!e orientated silicon steel) is shown. The characteristic is divided into three regions, define 'ankle-point' and the 'knee-point'. The w o r k i ~ grange of a protective current transformer e over the full range between the 'ankle-point' and the 'knee-point' and beyond, while a mea current transformer usually only operates in the region of the 'ankle-point'. The difference in working ranges between metering and protective current transformers stems from the radical difference in their functions. Metering current transformers work over the range 10% to 1 load and it is even an advantage if the current transformer saturates for currents above this range in order to provide thermal protection for the instruments. Protection current trans on the other hand are required t o operate correctly at many times-rated current-. : ; @

&&1x.. .@$ ,$X -;z': ,, . ; + i

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; A .: g (+

.gg .-.

' .::yzc **.

..c::

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...A

.-:<.I.'

b'

MMF ampere-turns per metre KNEE-POINT The knee-point of the excitation characteristic is defined as the point at which a 10% increase in secondary voltage produces a 50% increase in exciting current. It may, therefore, be regarded as practical limit beyond which a specified current ratio may be maintained.

.:

::.

!,

I

The current transformer magnetisationcurve, is usually expressed in terms of Kv and Ki which when multiplied by the flux density in teslas and ampere-turns per cm respectively gives corresponding volts and amperes :

Page 6

equation, the flux density 6 is in teslas and the core cross-sectional area is in squar

sity B is in teslas and the cross-sectional area is in square centimetres :

e exciting current le in amps can be obtained from the M'MF using the relationship: le = Ki x

MMF

I depend on the units of MMF. k l f the MMF is in ampere-turns per meter. S

3'

g. rf i

I?:;.

$.!

L Ki = - where L is in metres I1

g...

! EXAMPLE ' Consider the case of a current transformer

ratio 10015A connected to an earth fault relay. Relay

: burden at minimum tap setting of 1O0/0 of rated current is given as 2 VA. Calculate the required ' values of Kv and Ki to provide the necessary output up to 10 times the plug setting, with : 1

A barprimaryjype current transformer and with

ii)

A wound primary (5 turns current transformer).

Assume the use of a CROSS core; B = 1.6 tesla.

i)

Ring Type Current Transformer (Bar Frimaryj

,Relay current setting

=

Volts required to operate relay

L -- -

Voits required at iO times the the plug setting

.-

-

0.5 ampere : ie.lO% of 5A.

= 4 volts

0.5 =

4 x 10 = 40 volts ignoring lead burden and CT secondary winding resistance

Therefore, 40 volts must correspond to the knee-point of the saturation curve which represents a flux density of 1.6 tesla. With a bar primary, secondary number of turns = 20

Assume stacking factor = 0.92 .-. Gross CSA

= 56.310.92 = 61.2 cm2

Assuming : I.D. = O.D. = Depth =

18 cms 30 cms 10.2 cms

Wound Primary CT

,

..

--. . -

Assume current transformer is wound with 5 primsry turns :

l o o = 100 econdary turns = 5 x 5

-

49 = 4-44 x 53

x 1.6 100 x A. 7 9-4 (A in cm'j 7 .

m - le. csa

=

1 1.26 -= 12.24 cm' 0.92

18 cm 30 cm 2.04 cm

2 6 x 100 = 25 45 = 0.754 c m 1 turn

OPEN ClRCUlTED SECONDARY WINDING The secondary circuit of a current transformer should never be left open-circuited whilst primary continues to flow. In these circumstances only the primary winding is effective and thus the current transformer behaves.as a highly saturated choke (induction) to the flow of primary winding current. Thus a peaky and relatively high value of voltage appears at the secondary output of terminals, endangering life, not to mention the possible resulting breakdown of secondary circuit insulation. In those cases where current transformers are associated with the "high impedance type" earth fault relay the secondary circuit burden may have ohmic values up to several thousands of ohms.

Page 9

EQLIIVALENT CIRCUIT The errors of a current transformer may be considered as due to the whole of the primary current :& not being transformed, a component thereof being required to excite the core. Alternatively, we .. '2 may consider that the whole of the primary current is transformed without loss, but that the ,,,,;(: .-..~ secondary current is shunted by a parallel circuit the impedance of which is such that the ... ..2... equivalent of the exciting current flows there in. The circuit shown is the equivalent circuit of the ':1 current transformer.. The primary current is assumed to be transformed perfectly, with no ratio or phase single error, to a current Ip/N which is often called 'the primary current referred to the secondary'. A part of the curre'nt may be considered consumed in exciting the core and .this current leis called the secondary excitation current. The remainder Is is atrue secondary current. It will be evident that the excitation current is a function of the secondary excitatbn voltage Es and the secondary excitation impedance Ze. It will also be evident that the secondary current is a function of Es and the total impedance in the secondary circuit. This total impedance consists of the effective resistance (and any leakage reactance) of the secondary winding and the impedance of the burden.

.I!" .?..

primary current in amperes current transformer ratio (primary to secondary amperes) burden impedance of relays in ohms (r + jx) current transformer secondary winding impedance in ohms (r + jx) secondary excitation impedance in ohms Cjx) secondary excitation current in amperes secondary current in amperes secondary excitation voltage in volts secondary terminal voltage in volts across the current transformer terminal: (input to the relay or burden)

SATW RATION Beyond the knee-point the current transformer is said to enter saturation. In this region the major part of the primary current is utilised to maintain the core flux and since the shunt admittance is not linear, both the exciting and secondary currents depart from a sine wave. For example, in the case of a wholly resistive burden, correct transformation takes place until saturation flux density is reached. The secondary volts and current then collapse instantly to zero, where they

-

Page 10

Notes Additional Analysis

TRODUCTION

n

understanding and working knowledge of System Analysis is very important to the rotection Engineer as he must know how the system operates under load and fault conditions efore choosing suitable relays to match the system parameters. Analysis of load and fault conditions also provides useful information for :Choice of Power System Arrangement Required Breaking Capacity of Switchgear and Fusegear Application of Control Equipment Required Load and Short Circuit Ratings of Plant System Operation. Security of Supply, Economics Investigation of Unsatisfactory Plant.Perforrnance

-

110 = R

+

jX = Zi (cos 0 + jsin 0) =

i B 1 and Z2 = iZ2! JZ1l1Z21 LO, +(I2 and

z1 =--

22

.

= I-

Ijz2 i1

I

1 Z l ejO

L O 1 -(I2

OPERATORS

rotates a vector anti-clockwise through 90" a = 1 L120°

rotates a vector anti-clockwise through 120" used extensively in symmetrical component analysis

a2 = 1 L240°

a2 + a

+

1= 0

CONVENTION USED FOR VOLTAGE DIRECTION

I

-

Current I flowing in direction shown produces a voltage drop in Z such that A is positive with respect to B. !

\,

. - ..

Page 1

BASE QUANTITIES AND PER UNIT SYSTEM

3 This is particularly useful when analysing large systems with several voltage levels. Before any j?s system calculations can take place the system parameters must all be referred to common Q4+ base quantities. The base quantities are fixed on one part of the system and base quantities .-$ on other parts at different voltages will depend on the ratio of intervening power transformers. -1 The base quantities used are :,.<.::yr<*

Base voltage

kVb

=

2 :w

A .

=

Base MVA

.,>! ,:.;@$, 5 .-

phase to phase voltage in kV

=

MVAb

three phase MVA

=

..

-

-$ .r

..

-5 .,.>'

.v

Other base auantities can then be established :Base impedance

=

Base current

Ib F

=

Zb

-

~,

(kVb)' in ohms.

MVAb in M.

MVAb

J3.kvS

Per unit values are obtained by dividing actual values b y base values as follows :-

.

.

-

Per unlt ~mpedanceZp.u

-

Actual im~edance Base impedance

Z,

-

MVA

-

kVa

Per rlnit v n l t a n ~kV-

-

-

Per nit MVA M V A -

--

MVA, -

Per unit current I P u

-

la -

11,

Percentage values are commonly used for transformer impedances and where per unit values are very small. Percentage values are 100 times the equivalent per unit values.

Q

Page 2

..

- ,

. .r;y$

:% .:.:

L+

-

EXAMPLE 1

Find t h e fault current in e a c h section f o r a three p h a s e fault a t F.

Base kVb = 3 1 Base MVA

?,

b

= kv;

132

= 50 = 2.42~

MVA b

50 Z2.u 3 n 0.3 x - = 0.75,, common base 20

0.1 p u

FROM ONE SET OF BASE VALUES

p..

g.; g.

k:ti.

p $

:

.*.

Zp.u.2

-

zp.u,lx

i 2 MVAbl

MVAb2 (kvb2)* -

Page 3

The base voltage on each side of a transformer must be in the same ratio as the voltage ratio of the transformer.

C)!STR!BCITIS:4 SYSTEM

OVERHEAD LINE

mrrect Selection of kVb

11.8 kV

irrect Selection of kVb 132 x 11.8 = 11-05 kV

132 kV

I 1 kV

132 kV

I 1 kV

141-

$

>. iornative Selection of kVh 11.8 kV ,,,-...- Correction -.

141 kV

-

141x11 =11.75kV

EXAMPLE 3 ...

..

'.;

The per [,]nitimpedance of a transformer is the same on each side of the transforni e r Consider a transformer with voltage ratio kVllkV2.

I

1: i

I

0

MVA

0

Actual impedance of the transformer viewed from side 1 = Zal Actual impedance of the transformer viewed from side 2 = Za2.

zp.u 1

-

z a ~

-

-

Zp.u.2 -

Zbl

za2

= Zal

X

MVA kv12

- Za2 X MVA

-

kv2

zb2

but Za2 = Zal x

kv2 kv1

:.

Zp,u,2

-

-

Za1 x

MVA

= Z

L:

I

kV12

Page 5

CIRCUIT LAWS

There are three basic laws :

i)

Ohms Law

ii)

Kirchoffs Junction Law

'r

At any junction (or node) CI = 0:

'

i.e. 1, + I2 + l3 = 0

.

13

' -

iii)

Kirchoffs Mesh Law

Round any mesh CE = CIZ eg, in mesh (1):

El = il Z1 + il Z3

-

,

Page 6

- i2

Z3

.

CIRCUIT THEOREMS These are derived from the circuit laws. The three most commonly used for system analysis are Thevenins, Star/Delta Transform and Superposition Theorems.

i)

Thevenins Theorem This is useful for replacing part of a network which is noi of pan~cularinterest.

.

Any active network viewed from any 2 terminals can be replaced by a s~ngledrivirlg voltage in series with a s~ngleimpedance where :Driving voltage Impedance

=

=

Open circuit voltage between terminals Impedance of the network as viewed from the two terminals with all driving voltages short circuited.

Example :

Where E' =

-

L3.4 L3 E, and Z' = ---

z3

ii)

+

z1

z3

+

z1

DeltalStar and StarlOelta Transform Theorems

Page 7

212 =

z10

iii)

+

220

z10.z20 +

z30 z12.z31

ZI2+

+ Z31

Superposition Theorem In any linear network the current in any b r a ~ c h du different driving voltages is equal to the vector sum voltage acting alone with the others short circuited. Example :

I

l3 =

z1 1

131

+ 13? ..,.. ..,: ...-:

Page 8

INTRODUCTION .

In a balanced three-phase system, each of the three phases of any part of the system will have currents and voltages which are equal and 120° displaced with respect to each other. To maintain balanced operation, each Item of system plant must be symmetrical: i.e. have identical impedances In each line, equal mutual impedances between phases and ground, and equal

etween two lines and ground.

circuit faults. They can arise the operation of fuses.

SYMMETRICAL COMPONENTS METHOD

Consider n-dimensional system of phasors. Va = Val

+ Va2 + Va3 + ... + Van

Vb = Vbl

+ Vb2 + Vb3

+ ... +

Vbn

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . .

Vn = Vnl

Where

+ Vn2 + Vn3 + ... + Vnn

Val , Vbl , etc. are phasors of the first set of balanced n-phase system. Phasors are single spaced. . Va2 , Vb2 , etc. are phasors of the second set of balanced n-phase system. Phasors are double spaced.

Page 9

And so on.

.

Van , Vbn etc. are phasors of the uni-directional phasor system. Take for example an unbalanced 5-phase system. V, , Vb , V, , Vd , V.,

First set of aalanced Phasors

Second set of Balanced Phasors

Fourth set of Balanced Phasors

Fifth set of Zero Sequence Phasors

.

Now consider an unbalanced three phase system. Va Vb , V.,

A

vc1

Positive Sequence

v,. .

v t>

I fi Negative Sequence

vc2 Zero Sequence

. ..:$7 . ., 1

. , ,.. . T,.: .,

..

Three unbalanced phasors have been resolved into nine phasors. Choose 'a' phase as the reference phase and replace Vas by Vao.

where a = 1.0 L120° -

It is convenient to delete subscript 'a' for the symmetrical components.

Add equations 1. 2,and 3

2

Multiply equation 2 by u amd equation 3 by u and add the resulting equations to equation 1.

Multiply equation 2 by u2 and equation 3 by a and add the resulting equations to equation

Equations 1 to 6 can be re-written in matrix form

Re-write matrix equations 7 and 8 respectively as

1

[VP = [A]

PSI

....................

9

Where Vp = phase components Vs = sequence components

Example Resolve the following 3-phase unbalanced voltages into their symmetrical components.

Fig. 1 Symmetrical Components

t;:

E

SYMMETRICAL COMPONENT TRANSFORMATION

,

..

Fig. 2

/ . ?

Take a set of symmetrical three phase impedances (equally spaced, fully transposed, etc.) carrying unbalanced phase currents L a , Ib and I,.

\

.

We may write the following equations. Va = Zsla + Zmlb + Zmlc

where Zs = self impedance per phase

Z,

= mutual impedance betrween any ~ h a s e pair

Or, in matrix form

Resolving V and 1 phasors into their symmetrical components.

. I

Page 15

=

[: I

where

2:a

I; [i i; [i ;*I

a

;2

Z1 = Z, - Z,

Therefore, if the system is. symmetrical in its normal state the symmetrical co~~?poiaent impedance becomes diagonal (equation 11) and, therefore, isolated sequence networks are . obtained with impedances Z1, Z2 and Zo. These three networks will become interconnected when an unbalance such as a fault or unbalanced loading is introduced. The manner of interconnection will depend on the new constraints: i.e. the additional system connect~or~s.

Page 16

r F $

PLANT IMPEDANCE DATA

F

-

For static networks i.e. non-rotating plants, the positive and negative sequence Impedances are the same. These are the leakage impedance of the transformers and the normal phase impedance of the transmission circuits. Zero sequence impedance of overhead line and cable circuits is determined by the return path of the zero sequence currents through earth, earth wires or cable sheaths. The zero sequence impedance is generally' greater than the positive and negative sequence impedance, being usually of the order of two to three times the positive sequence value in the case of overhead lines. For transformers, if zero sequence currents have an available path and can flow, they will again see the leakage reactance in each phase. If no path exists, an open circuit must be shown for the particular windings in the zero sequence network. The flow of zero sequence current in any winding is possible only if other windings provide a path for the flow of balancing zero sequence currents.

,-

Consider the transformer equivalent circuit in F~gure3 overleaf. The magnet~singimpedance Z , is of the order of 2000°/~, compared to the leakage impedance ZIP + Z1, of about 10%. Therefore, magnetising impedance can be ignored and the transformer can be represented in the positive and negat~vesequence networks by a series impedance (=ZIP+ Z,,).

1

1. -. . . ..... J .

.. ....-

ZL*

I

0

> .

...

Zm

1

O

zLp=

primary winding leakage impedance Z1, = secondary winding leakage impedance Zm = rnagnetising impedance

Fig. 3 Transformer Equivalent Circuit

In the zero sequence network, although the leakage impedance is identical to the positive sequence value (when zero sequence path is available) the zero sequence rnagnetising impedance is dependent upon the transformer core construction and can be much lower. In three-phase banks of single phase transformers and in three-phase shell cored transformers, the zero sequence magnetising impedance is ,large and can be ,ignored as in the positive and negative sequence networks. In three-limb core type transformers, however, the zero sequence flux must be completed through the oil or tank. Owing to the high reluctance of the flux path, zero sequence magnetising impedance is of the order of only 100% to 400%. However, this is still high enough to be neglected in most fault studies, particularly when a delta winding Is present.

-

I

Page 17

Therefore, consider zero sequence circuit of transformer as a series impedance Zt. The mode of connection of Z, to the external circuit is determined by taking account of each winding arrangement and its connection or otherwise to ground. -

Imaginary links 'a' and 'b' (see Figure 4) are used to derive the connections. If zero sequence currents can flow into and out of a winding, for example a solidly earthed star winding, the winding terminal is connected to the external circuit, that is link 'a' is closed. 'a'

'a'

Fig. 4 ,!:

k d'

..ti:.

If zero sequence currents can circulate in the winding without flowing in the external circuit, for example a delta winding, the winding terminal is directly connected to the zero bus, that is link 'b' is closed.

..

'

!i .

il:

-

b Example 1

..:

'a'

'a'

Zero Sequence Equivalent Circuit Connections -

Page 18

.*.

..iL ...

-.;

m

i h e zero sequence impedance of a neutral earthing impedance Zn is 32.. can be readily understood from Figure 5 below.

I

At the neutral point the zero sequence currents I0 in the three phases combine to give 310 in the neutral earthing impedance. The zero sequence voltage at the neutral point is given by

. .

The reason for this

vo =

3I0Zn

.

.

.

zo = vo = 32"

.

.

.. .

.

.

.

.. .

.

. . .. -. .

.

.

.

.

.

.

lo

Example 2

-

Transformer Connections

'a'

'a'

Zero Sequence Equivalent Circuit Connections

.

.

Page 19

3R

.

.

:

.

.

. .

.

. .

-

The positive sequence impedance of synchronous machines is the normal machine reactan There are three defined values of positive sequence impedances, namely the synchron transient and subtransient impedances and they are used according to whether steady st transient or initial short-circuit values of current are required.

L

&

Unlike the non-rotating networks, the negative sequence impedance of the rotating plants is equal to the positive sequence impedance. It relates to mmf at synchronous speed travelli the opposite direction to the rotor. Its value is usually less than that of the positive sequ impedance. , <.,.,~<

.. .~.. ., . ..... ..

,'.;!&

In the zero sequence network, the winding connection and earthing arrangement must be considered as for transformers. Any earthing impedance will be seen by each phase and therefore the correct voltages will be obtained if three times the impedance value is included in the zero sequence network.

'$$$

.;$@

.

. .,?. :,.;3j? .,;: Y% . %.

,

. s. .,/?;.,T?. ..

",:,e"' ;, G.

Typical turbo-generator sequence reactances are : synchronous reactance transient reactance subtransient reactance negative sequence impedance zero sequence impedance

--

,:a?%! .....;,.:.4::

1.0 p.u. 0.15 p.u. 0.10 p.u. 0.13 p.u. 0.04 p.u.

= -

.:.> ,,

,

.

CONNECTION OF SEQUENCE NETWORKS TO REPRESENT UNBALANCED FAULTS

A

>.+<;-, .%:. . .. .+....<.

. . .:. .,&xS!

.

,*-

"

. .

:

,

For anygiven fault there a% six quantities'to be mnsidered at the.fault point; Vat Vb, V,, I,, It,, lc. If any three are known(provided they are not all voltagesor all currents) or.if any two are known and two others known to have a specific relationship, then a relationship between V1,Vp and Vo and 11, 12 and 10 can be established.

d

. :;T.><.>. Z&, '>.c:~ .. <. 6. . ~ . >. -

. .

(a)

.". .., .,

",:$:<'

.'.,?' ., ~

.

-

y!j$

.

~

.

4

.:,:.:<:.

:.:$&$ ..,:-, ":r .,.

. . .

..

~.!j~$v.,, i :2-%

...-. .;:!

..,? . . ,.

t . ' f .

.. .'...:.

:

-

..

These relationships are-called the circuit constraints.

- ...?

From the circuit constraints we can determine the manner in which the isolated sequence networks can be interconnected.

,: . ..

,...

.%.

. ,. . . ...

(b)

The relationships are derived with phase 'a' as the reference phase and the faults are selected to be balanced relative to the reference phase. This yields the simplest interconnection of the sequence networks. If this is not done the interconnections of the sequence networks require additional transformations which are achieved by the introduction of phase shifting transformers. This will be apparent in the case of simultaneous faults where it is not possible for both the faults to be symmetrical about the reference phase.

:.,?" .$$: *

;:,

...$ ,.:(,

..:? :.

..

..:;yfi

.:$

I

Page 20

:: :) ..?

i t Faults

F;

ine-to-ground faults, line-to-line faults, line-to-line to ground faults and three phase faul'ts all ,fall into the category of shunt faults. /(a)

\:

,

i, I

, (b)

Figure 6 shows a system with a fault at F. The positive, negative and zero sequence networks of the system are shown in Figure 7. The fault terminals for the positive sequence network are F1 and N1, and the corresponding fault terminels for the negative and zero sequence networks are F2, N2 and Fo, No respectively. It is at these terminals that the interconnection of the networks will occur. In the denvation of sequence network interconnections, it is convenient to show the sequence networks as blocks with fault terminals F and N for external connections (F~gure8) To derive the system constraints at the fault terminals, it IS convenient to imagine three short conductors of zero impedance connected to the three line conductors at the point of fault (F~gure9). The terminal conditions imposed by the different types of faults will be applied to these imaginary leads, t h e potential to ground of which will be V, Vb and V, and the currents ,I I b and I,. .,

A

I

B

Fig. 9

--

-Fis. 6 Single Line Diagram of Two Machine System

PF

6 ~ ,

. Pos~tiveSequence Network of System

@ Sequence & k k

of System

Fiq. 7 Sequence Networks of Faulted S y s t e ~

Sequence Network

Sequence Network etwork Blocks

Page 22

Line to Ground on Phase 'A' At fault point :

We know from section (2.2)that

v,

=

v,

+

v*

+

vo

But Va = 0 .'.

v, + v 2 + v o = o---------------------

3

We know from section (2.2) that

But :.

10

= 1/3(la+

lb

= Ic= 0

l b +

1,)

.-

10 = 113 ,1 L

Also, l1 = 113 (Ia + ulb + a I,) 12

= 113 (I,

+

2

u

lb +

= 113 1,

ul,) '= 113 ,I

Equations 3 & 4 are the CIRCUIT CONSTRAINTS. They suggest that the sequence netwo are connected in series. -

Sequence Network

Network

Network

Page 23

Line to Ground Fault through Fault Impedance ZF At fault point :

We know from section (2.2) that

:.

I0 = 113 ,I

since lb = 1,

= 0

Similarly,

:. 11 = 12 = 10 = 113 1,

3

We know

But V,

= I,Zf from constraint 2

But 1, = 310 from equation 3

Equations 3 & 4 suggests the following interconnections.

-

+ve Sequence Network

11

F1 A

N1

-

-ve

12

F2

Network

F4

-

Zero Sequence Network

lo

Fo

-

No

Page 24

Line to Line Fault on Phases 'B' and 'C' At fault point :

.

.....................

We know l o = '113 (I, + I b + I,)

4

-

Substituting equations 2 & 3 into equation 4,

Similarly, 2

11= 1/3(Ia + a l b + u I,) 2

12 = 113 (I, + a I b + uI,)

2

= 1/3(a-a) 2

= -113 ( a - a )

Ib Ib

.....................

:. I1 + 12 = 0

6

Substituting equation 1 into equation 7, V1 = 113 (V,

- Vb)

Similarly V2 = 113 (V,

2

+ a Vb + a ~ i = ) 113 (V,

- Vb)

From equations 5, 6 & 8, the positive and negative sequence networks are in parallel but the zero sequence network is unconnected.

Sequence Network

Sequence Network

Sequence Network No

Line to Line Fault on Phases 'B' and 'C' through Fault Impedance ZF

Page 25

At point of fault,

I, = 0 Ib +

lc = 0

Vb - Vc = IbZf

:. 10

= 113 (la + Ib + I,)

11 =

2 .2 113 (I, + a l b + a 1,) = 113 (a - a ) lb 2

1 2 = 113(1, + a :.

= 0

Ib +

2

al,)

= -1/3(a-a)lb

.....................

I0 = 0 I1 +

4

I2 = 0

2 We know Ib = 10 + a I l + u12 )

--------------------- 5

-

Substituting equation 4 in 5

Vb = VO + V,=

aLvl +

aV2 2

Vo + rxVl + cr V2

... V b - V C =

(a2 - a ) V 1

- (a2 - a ) V 2

.....................

7

Substitute equation 3 8 6 into 7,

+

Equations 4 8 8 suggest the following interconnections.

Sequence Network

Sequence Network

N

I

I Line to Line to Ground Fault on Phases 'B' and 'C'

Page 26

Network

At fault point :, vb

=

vc = 0

I, = 0

2

V2 = 113 (V,

+ a Vb + UV,)

= 113 V,

From equation 3 & 4, it can be concluded that the sequence networks are connected in parallel.

-

11

-C-OFl +ve Sequence Network

-ve

-

Sequence Network

O N 1 -

12 w F

-

2

ON

-FO

Zero Sequence Network

Line to Line to Ground Fault on Phases 'B' and 'C' through Fault Impedance Z, At fault point :,

Page 27

QNO

V1 = 113 (V,

v2 =

+ aVb +

113(~, +

2. . a vc)

a2vb+

-

2

+ (a + a)Vbl = II~(v,-

aVc) = II~[V,

.....................

5

(Ib + )1, Zf .....................

6

.'. v1 = v2 Vo

2

= 113 [V, + (a + a)Vb] = 113 (Va- Vb) vb)

Vl = 113 (2Vb + Vb) = Vb -

-

Substitute equation 4 in 6

vo - v1 =

31ozf

Equations 3, 5 and 7 suggest the following interconnections.

+ve

-

-

-L

11 -FI

-ve Sequence Network

Network N1

I2

t

-- l o

~2

Zero sequence Network

~2

ON /

Page 28 -

Fo

L.

N

3Zf

1.

SERIES FAULTS (or Open Circuit Faults) (a)

Figure 1 shows a system with an open circuit PQ. The positive, negative and zero sequence networks of the open-circuited system are shown in Figure 2. Unlike the case of shunt faults, the fault terminals for interconnection are P and Q, therefore not I nvolving the neutral. The sequence equivalent network blocks (Figure 3) will have terminals P and Q for interconnection. Terminal N is also indicated in the blocks although it is not used for interconnections.

(b)

The terminal conditions imposed by different open circuit faults will be applied across points P and Q on the three line conductors (see Figure 4). Therefore the fault terminal currents will be IA, IB and Ic flowing from P to Q on the three conductors, and the terminal potentials will be the potential across P and Q, i.e. V,

- V,',Vb - Vbl, Vc - V;

They will be represented by v,

Figure 4

Page 29

vb and vc respectively.

Training _ Power System Protection _AREVA

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