Condenser Maintenance and Operation

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Condenser Application and Maintenance Guide

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1003088

© 2001 Electric Power Research Institute (EPRI), Inc. All rights reserved. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric Power Research Institute, Inc. Printed on recycled paper in the United States of America 1003088

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M AT E

Plant Maintenance Support

Equipment Reliability

Condenser Application and Maintenance Guide 1003088

Final Report, August 2001

EPRI Project Manager A. Grunsky


DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT EPRI

ORDERING INFORMATION Requests for copies of this report should be directed to EPRI Customer Fulfillment, 1355 Willow Way, Suite 278, Concord, CA 94520, (800) 313-3774, press 2. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric Power Research Institute, Inc. Copyright © 2001 Electric Power Research Institute, Inc. All rights reserved.

CITATIONS This report was prepared by Nuclear Maintenance Applications Center (NMAC) EPRI 1300 W.T. Harris Boulevard Charlotte, NC 28262 This report describes research sponsored by EPRI. The report is a corporate document that should be cited in the literature in the following manner: Condenser Application and Maintenance Guide, EPRI, Palo Alto, CA: 2001. 1003088.

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REPORT SUMMARY

The Condenser Application and Maintenance Guide provides plant personnel with information on the operation, maintenance, and performance of condensers. The contents of this guide will assist the plant in improving condenser performance, reducing maintenance costs, and in increasing condenser reliability. Background As the age of a condenser increases, the maintenance costs required for continued operation of the condenser also increase. Unit reliability and lost energy costs are affected by condenser performance. Objectives x To provide station personnel with reliability, performance, and maintenance practices for the condenser. x

To provide a comprehensive guide for condenser equipment.

Approach This guide is structured to provide a comprehensive overview of condenser equipment. An extensive search of previously written EPRI guidelines was conducted to provide relevant information for plant personnel in the operation, maintenance, and performance of the condenser. Utility and industry personnel provided input into the development of this guide. Results The guide includes information on the condenser types, component information, troubleshooting operational problems, performance calculations and instrumentation, macrofouling and microfouling control techniques, mechanical and chemical cleaning, air and water in-leakage detection and correction methods, industry failure data, mechanisms and corrosion prevention practices, preventive maintenance tasks, non-destructive examination testing and results, tube plugs, inserts, sleeves, coatings, liners, staking, waterbox and tubesheet repairs, remaining life assessment, component materials, constructability issues, retubing, rebundling, and the results of an industry survey. The guide includes the following sections: x

Introduction

x

Tutorial

x

Troubleshooting v

x

Performance

x

Fouling

x

Cleaning

x

Air/Water In-Leakage

x

Failure Modes

x

Condition-Based Maintenance

x

Maintenance Repairs

x

Remaining Life, Materials, and Constructability

EPRI Perspective Condenser operation and maintenance costs increase as the age of a condenser increases. Unit reliability and lost energy costs are affected by condenser performance. This guide provides a comprehensive overview of the equipment practices needed for continued reliable operation. Keywords Condenser Performance Maintenance Reliability Fouling Cleaning

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ABSTRACT The condenser is a critical component in a nuclear power plant. As the age of a condenser increases, the maintenance costs required for continued operation also increase. Fouling affects condenser performance and cleaning is required to restore performance. Troubleshooting problems with high condenser pressure is a common occurrence. Condition-based maintenance is important for long-term reliability of this equipment. Tube leaks are the primary cause of lost production caused by the condenser. Maintenance repairs include installing tube plugs, inserts, sleeves, shields, coatings, liners, tube bundle stakes, and waterbox and tubesheet repairs. Retubing might be needed to restore performance. This guide is a comprehensive treatment of all aspects of condenser maintenance and is to be used by plant maintenance engineers to improve condenser performance and reduce maintenance costs.

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EPRI Licensed Material

ACKNOWLEDGMENTS The Condenser Application and Maintenance Guide was produced by the Nuclear Maintenance Applications Center (NMAC) and the following members of the Condenser Guide Technical Advisory Group (TAG). NMAC would like to thank the following individuals for their participation in the preparation and review of this report. Technical Advisory Group Members: Name Tim Eckert Chuck George John Harvey Bob Littlejohn Dennis Mason Eric May Mark Meltzer Eric Steckhan

Utility EPRI Plant Support Engineering Carolina Power & Light Entergy Operations, Inc. Tennessee Valley Authority Duke Power Company Dominion Nuclear Services Public Service Electric & Gas Exelon Corporation

Name Bob Boberg Chris Johnson Jim Mitchell George E. Saxon, Jr. Fritz Sutor

Vendor Framatome Technology Heat Exchanger Institute Plastocor, Inc. Conco Systems, Inc. Expansion Seal Technologies

NMAC and the Technical Advisory Group were supported in their efforts to develop this guide by: Sharon R. Parker

EPRI NMAC Contractor

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CONTENTS

1 INTRODUCTION.................................................................................................................. 1-1 1.1

Background............................................................................................................... 1-1

1.2

Approach................................................................................................................... 1-2

1.3

Guide Organization ................................................................................................... 1-2

1.4

Pop-Outs................................................................................................................... 1-3

2 TUTORIAL........................................................................................................................... 2-1 2.1

Condenser Operation ................................................................................................ 2-1

2.2

Rankine Cycle ........................................................................................................... 2-4

2.3

Condenser Secondary Functions .............................................................................. 2-5

2.4

Condenser Types...................................................................................................... 2-6

2.4.1 Single-Compartment, Single-Pass, Transverse Flow Condenser.......................... 2-7 2.4.2 Single-Compartment, Two-Pass, Transverse Flow Condenser............................. 2-8 2.4.3 Two-Compartment, Single-Pass, Transverse Flow, Parallel Design Condenser ..................................................................................................................... 2-9 2.4.4 Two-Compartment, Single-Pass, Transverse Flow, Series Design Condensers ................................................................................................................... 2-9 2.4.5 Two-Compartment, Single-Pass, Axial Flow Condenser..................................... 2-10 2.4.6 Three-Compartment, Single-Pass, Transverse Flow, Parallel Design Condenser ................................................................................................................... 2-11 2.4.7 Three-Compartment, Single-Pass, Transverse Flow, Series Design Condenser ................................................................................................................... 2-11 2.4.8 Three-Compartment, Single-Pass, Axial Flow Condenser .................................. 2-12 2.4.9 Three-Compartment, Single-Pass, Axial Flow, Middle Waterbox Condenser...... 2-13 2.5

Condenser Components ......................................................................................... 2-13

2.5.1 Condenser Shell ................................................................................................. 2-14 2.5.2 Hotwell ............................................................................................................... 2-14 2.5.3 Waterbox ............................................................................................................ 2-14 2.5.4 Tubesheet .......................................................................................................... 2-14

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2.5.5 Tubes ................................................................................................................. 2-15 2.5.6 Air-Removal Equipment...................................................................................... 2-15 2.5.6.1 Steam Jet Air Ejector................................................................................... 2-16 2.5.6.2 Vacuum Pump............................................................................................. 2-18 3 TROUBLE-SHOOTING........................................................................................................ 3-1 3.1

Increased Condenser Pressure................................................................................. 3-1

3.2

Air Binding Problems................................................................................................. 3-3

3.3

Air-Removal Equipment Problems............................................................................. 3-5

3.3.1 Poor Vacuum........................................................................................................ 3-5 3.3.2 Gradual Loss of Vacuum ...................................................................................... 3-7 3.3.3 Poor Vacuum and/or High Outlet Water Temperature........................................... 3-7 3.3.4 Faulty Operation of the Steam Jet Air Ejectors ..................................................... 3-7 3.3.5 Ejector Field Testing............................................................................................. 3-9 3.3.6 Problems with Liquid Ring Vacuum Pumps (LRVPs) ............................................ 3-9 3.3.7 LRVP Checklist of Operating Variables .............................................................. 3-11 4 PERFORMANCE ................................................................................................................. 4-1 4.1

Heat Transfer ............................................................................................................ 4-1

4.1.1 Condensate Subcooling........................................................................................ 4-2 4.1.2 Hotwell Subcooling ............................................................................................... 4-3 4.2

Condensing Duty....................................................................................................... 4-4

4.3

Heat Transfer Coefficient .......................................................................................... 4-5

4.4

HEI Method ............................................................................................................... 4-6

4.5

ASME Method ........................................................................................................... 4-7

4.6

Turbine Blade Effects ................................................................................................ 4-9

4.7

Performance Monitoring .......................................................................................... 4-10

4.8

Performance Software Tools ................................................................................... 4-11

4.9

Instrumentation ....................................................................................................... 4-12

4.9.1 Condenser Pressure........................................................................................... 4-13 4.9.2 Air In-Leakage .................................................................................................... 4-14 4.9.3 Condensate Oxygen........................................................................................... 4-15 4.9.4 Hotwell and Condensate Temperature ............................................................... 4-16 4.9.5 Circulating Water Flow........................................................................................ 4-16 4.9.5.1 Velocity Traversing ...................................................................................... 4-16

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4.9.5.2 Dye Dilution Testing .................................................................................... 4-17 4.9.5.3 Sonic Flow Devices ..................................................................................... 4-18 4.9.6 Pump Curves and Total Dynamic Head.............................................................. 4-18 4.9.7 Flow Monitor Technique ..................................................................................... 4-18 4.9.8 Circulating Water Temperature........................................................................... 4-19 4.9.9 Pressure Drop .................................................................................................... 4-20 4.9.10 Waterbox Levels ............................................................................................... 4-20 5 FOULING............................................................................................................................. 5-1 5.1

Macrofouling ............................................................................................................. 5-1

5.1.1 Saltwater Organisms ............................................................................................ 5-2 5.1.2 Freshwater Organisms ......................................................................................... 5-3 5.2

Macrofouling Control Technologies ........................................................................... 5-4

5.2.1 Mechanical Controls ............................................................................................. 5-4 5.2.1.1 Trash Racks .................................................................................................. 5-6 5.2.1.2 Trash Rakes.................................................................................................. 5-6 5.2.1.3 Traveling Water Screens ............................................................................... 5-8 5.2.1.4 Debris Filters ............................................................................................... 5-10 5.2.2 Flow Reversal..................................................................................................... 5-11 5.2.3 Thermal Backwash ............................................................................................. 5-11 5.2.4 Hydraulic Control ................................................................................................ 5-12 5.2.5 Materials Control ................................................................................................ 5-12 5.2.6 Chlorination and Alternate Biofouling Control Methods ....................................... 5-13 5.2.7 Manual Cleaning................................................................................................. 5-14 5.3

Microfouling............................................................................................................. 5-14

5.3.1 Biofilm Development........................................................................................... 5-15 5.3.1.1 Phase Development .................................................................................... 5-15 5.3.1.2 Developing Factors...................................................................................... 5-17 5.3.2 Chemical Fouling................................................................................................ 5-18 5.4

Microfouling Chemical Treatment ............................................................................ 5-19

5.4.1 Cooling System Design and Operation ............................................................... 5-19 5.4.2 Biocontrol Agents ............................................................................................... 5-20 5.4.2.1 Oxidizing Biocides ....................................................................................... 5-20 5.4.2.2 Non-Oxidizing Biocides ............................................................................... 5-20 5.4.2.3 New Biocides............................................................................................... 5-22

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5.4.3 Water Regulations .............................................................................................. 5-23 5.4.3.1 Technology-Based Regulations................................................................... 5-23 5.4.3.2 Historically Based Effluent Water Quality Standards.................................... 5-25 5.4.3.3 Receiving Water Quality-Based Standards.................................................. 5-25 5.4.4 Chemical Application Methods............................................................................ 5-26 5.4.4.1 Chlorine....................................................................................................... 5-27 5.4.4.2 Bromine....................................................................................................... 5-31 5.4.4.3 Non-Oxidizing Biocides ............................................................................... 5-34 5.5

Fouling Monitor ....................................................................................................... 5-35

5.6

Targeted Chlorination With Fixed Nozzles............................................................... 5-36

6 CLEANING .......................................................................................................................... 6-1 6.1

Mechanical On-Line Cleaning Systems ..................................................................... 6-4

6.1.1 Sponge Ball System ............................................................................................. 6-4 6.1.2 Brush and Cage System..................................................................................... 6-11 6.1.3 Self-Aligning Rockets.......................................................................................... 6-14 6.2

Mechanical Off-Line Cleaning Systems ................................................................... 6-15

6.2.1 Air/Water-Driven Systems .................................................................................. 6-16 6.2.2 Mechanically Driven Systems ............................................................................. 6-19 6.2.3 Pressure-Driven Systems ................................................................................... 6-19 6.2.4 Waste Disposal................................................................................................... 6-20 6.2.5 Advantages and Disadvantages of Off-Line Systems ......................................... 6-20 6.3

Chemical Cleaning .................................................................................................. 6-22

7 AIR/WATER IN-LEAKAGE.................................................................................................. 7-1 7.1

Air In-Leakage Effects ............................................................................................... 7-1

7.1.1 Air In-Leakage Costs ........................................................................................... 7-2 7.1.2 Condensate/Feedwater Chemistry........................................................................ 7-4 7.1.3 Condensate Reheating ......................................................................................... 7-5 7.1.3.1 Condensate Steam Sparging......................................................................... 7-5 7.1.3.2 Hotwell Deaeration ........................................................................................ 7-6 7.1.3.3 Condenser Drains ......................................................................................... 7-6 7.1.3.4 Makeup Water ............................................................................................... 7-7 7.2

Air In-Leakage Detection Methods ............................................................................ 7-7

7.2.1 Tracer Gas Testing............................................................................................... 7-8

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7.2.1.1 Tracer Gas Equipment ................................................................................ 7-11 7.2.1.2 Data Interpretation....................................................................................... 7-14 7.2.1.3 Tracer Gas Selection................................................................................... 7-14 7.2.1.4 Testing Areas .............................................................................................. 7-15 7.2.1.5 Air In-Leakage Checklist.............................................................................. 7-16 7.2.1.6 Off-Line Testing........................................................................................... 7-21 7.2.2 Multisensor Probe............................................................................................... 7-22 7.2.3 Infrared Technology............................................................................................ 7-23 7.3

Correcting Air In-Leakage ....................................................................................... 7-24

7.4

Water In-Leakage Effects........................................................................................ 7-25

7.4.1 Condensate Chemistry Detection ....................................................................... 7-26 7.4.2 Water Leakage in PWRs .................................................................................... 7-28 7.4.3 Water Leakage in BWRs .................................................................................... 7-29 7.5

Water In-Leakage Detection Methods ..................................................................... 7-30

7.5.1 Tracer Gas Method............................................................................................. 7-31 7.5.2 Plastic Film Testing ............................................................................................ 7-31 7.5.3 Soap Film Testing............................................................................................... 7-32 7.5.4 Non-Destructive Methods ................................................................................... 7-32 7.5.5 Smoke Method ................................................................................................... 7-32 7.5.6 Rubber Stoppers ................................................................................................ 7-32 7.5.7 Individual Tube Pressure/Vacuum Testing.......................................................... 7-33 7.5.8 Hydrostatic Testing............................................................................................. 7-33 7.5.9 Miscellaneous Problems..................................................................................... 7-33 7.5.10 On-Line Leak Detection .................................................................................... 7-34 7.6

Correcting Water In-Leakage .................................................................................. 7-36

8 FAILURE MODES ............................................................................................................... 8-1 8.1

Failure Data .............................................................................................................. 8-1

8.1.1 Just-in-Time Operating Experience....................................................................... 8-2 8.1.2 Significant Event Evaluation Information Network (SEE-IN).................................. 8-2 8.1.3 Licensee Event Reports (LERs)............................................................................ 8-4 8.1.4 Plant Events Database ......................................................................................... 8-6 8.1.5 Operating Plant Experience Code (OPEC) ........................................................... 8-8 8.2

Failure Mechanisms ................................................................................................ 8-10

8.2.1 Condensate Corrosion........................................................................................ 8-10

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8.2.2 Crevice Corrosion............................................................................................... 8-11 8.2.3 Dealloying........................................................................................................... 8-11 8.2.4 Erosion-Corrosion............................................................................................... 8-14 8.2.5 Galvanic Corrosion ............................................................................................. 8-16 8.2.6 General Surface Corrosion ................................................................................. 8-17 8.2.7 Hydrogen Damage ............................................................................................. 8-17 8.2.8 Random Pitting ................................................................................................... 8-18 8.2.9 Steam Side Erosion............................................................................................ 8-19 8.2.10 Stress Corrosion Cracking ................................................................................ 8-19 8.2.11 Vibration Damage ............................................................................................. 8-20 8.2.12 Summary of Failure Mechanisms ...................................................................... 8-21 8.3

General Corrosion Prevention Practices.................................................................. 8-22

8.3.1 Cathodic Protection ............................................................................................ 8-22 8.3.2 Debris Filtration/Removal ................................................................................... 8-26 8.3.3 Proper Lay-Up .................................................................................................... 8-27 8.3.4 Design Modifications .......................................................................................... 8-27 9 CONDITION-BASED MAINTENANCE ................................................................................ 9-1 9.1

Records .................................................................................................................... 9-1

9.2

Periodic Inspections .................................................................................................. 9-1

9.2.1 Waterbox .............................................................................................................. 9-1 9.2.2 Tubesheet ............................................................................................................ 9-2 9.2.3 Hotwell ................................................................................................................. 9-3 9.2.4 Tube Bundles ....................................................................................................... 9-3 9.2.5 Structural Components ......................................................................................... 9-3 9.3

Preventive Maintenance (PM) ................................................................................... 9-4

9.3.1 Cleaning ............................................................................................................... 9-4 9.3.2 Performance Monitoring ....................................................................................... 9-4 9.3.3 Operator Rounds .................................................................................................. 9-5 9.3.4 Preventive Maintenance Summary Tables............................................................ 9-5 9.4

Non-Destructive Examination (NDE) ....................................................................... 9-14

9.4.1 Magnetic Particle Testing (MT) ........................................................................... 9-14 9.4.2 Liquid Penetrant Testing (PT) ............................................................................. 9-14 9.4.3 Ultrasonic Testing (UT)....................................................................................... 9-15 9.4.4 Eddy Current Testing (ET) ................................................................................. 9-15

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9.4.4.1 Planning the Eddy Current Test................................................................... 9-17 9.4.4.2 Tube Map .................................................................................................... 9-18 9.4.4.3 Benchmark Data Set ................................................................................... 9-18 9.4.4.4 Data Comparisons and Trending ................................................................. 9-18 9.4.4.5 Maintenance Practices ................................................................................ 9-19 9.4.4.6 Figures of Merit ........................................................................................... 9-19 9.4.4.7 Management Report.................................................................................... 9-19 9.4.4.8 Pre-Outage Activities................................................................................... 9-19 9.4.4.9 Outage Activities ......................................................................................... 9-21 9.4.4.10 Post-Outage Activities ............................................................................... 9-21 9.4.4.11 ET Flowchart ............................................................................................. 9-21 10 MAINTENANCE REPAIRS.............................................................................................. 10-1 10.1 Plugging Tubes ....................................................................................................... 10-1 10.1.1 Preparation for Tube Plugging .......................................................................... 10-2 10.1.2 Tube Plug Selection .......................................................................................... 10-3 10.1.3 Tube Plug Types............................................................................................... 10-3 10.1.3.1 Hammer-In Taper Plugs ............................................................................ 10-3 10.1.3.2 Elastomer Plug .......................................................................................... 10-5 10.1.3.3 Mechanical Plug ........................................................................................ 10-9 10.1.3.4 Welded Tube Plug ................................................................................... 10-10 10.1.3.5 Tube Plugs Available............................................................................... 10-11 10.1.4 Tube Plug Removal......................................................................................... 10-15 10.1.4.1 Hammer-In Taper Plugs .......................................................................... 10-15 10.1.4.2 Elastomer Plugs ...................................................................................... 10-16 10.1.4.3 Mechanical Plugs .................................................................................... 10-16 10.1.4.4 Welded Plugs .......................................................................................... 10-16 10.2 Tube Inserts .......................................................................................................... 10-17 10.3 Tube Sleeves ........................................................................................................ 10-19 10.4 Tube End Coatings ............................................................................................... 10-20 10.5 Full-Length Tube Liners ........................................................................................ 10-21 10.6 Full-Length Tube Coatings .................................................................................... 10-22 10.7 Re-Expanding the Tube-to-Tubesheet Joint .......................................................... 10-24 10.8 Coating of Tubesheets .......................................................................................... 10-24 10.9 Tube Staking for Vibration..................................................................................... 10-25

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10.10Waterbox Repairs ................................................................................................. 10-29 10.10.1 Waterbox Coating Techniques...................................................................... 10-30 10.10.2 Waterbox Flange Seams .............................................................................. 10-32 10.11Tubesheet Repairs................................................................................................ 10-32 10.12Tube Pulling .......................................................................................................... 10-33 10.13Miscellaneous Repairs .......................................................................................... 10-33 11 REMAINING LIFE, MATERIALS, AND CONSTRUCTABILITY....................................... 11-1 11.1 Remaining Life Assessment .................................................................................... 11-3 11.1.1 NDE Testing Techniques Used to Assess Remaining Life ................................ 11-3 11.1.2 Remaining Life Formula .................................................................................... 11-4 11.2 Tube Material Selection........................................................................................... 11-5 11.2.1 Titanium ............................................................................................................ 11-6 11.2.2 High Performance Stainless Steels ................................................................... 11-6 11.2.2.1 Initial Installations ...................................................................................... 11-8 11.2.2.2 Water Type Significance............................................................................ 11-9 11.2.2.3 Tube-Related Problems............................................................................. 11-9 11.2.3 Austenitic Stainless Steel ................................................................................ 11-14 11.2.4 Copper Alloys.................................................................................................. 11-14 11.2.5 Summary of Material Specification .................................................................. 11-15 11.2.6 Material Comparison ....................................................................................... 11-16 11.3 Tubesheet Joints and Material Selection ............................................................... 11-16 11.3.1 Expanded Joint ............................................................................................... 11-17 11.3.2 Expanded and Grooved Joint.......................................................................... 11-18 11.3.3 Packed Joint ................................................................................................... 11-18 11.3.4 Expanded and Welded Joint ........................................................................... 11-18 11.3.5 Joint Adhesives............................................................................................... 11-19 11.3.6 Material Selection ........................................................................................... 11-19 11.4 Waterbox and Shell Materials................................................................................ 11-22 11.5 Constructability Issues .......................................................................................... 11-22 11.5.1 Retubing ......................................................................................................... 11-22 11.5.1.1 Waterbox Removal and Installation ......................................................... 11-23 11.5.1.2 Tube Removal ......................................................................................... 11-24 11.5.1.3 Breaking Tubesheet Joints ...................................................................... 11-24 11.5.1.4 Removing Tubes ..................................................................................... 11-25

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11.5.1.5 Tubesheet Replacement ......................................................................... 11-25 11.5.1.6 Support Plate Deburring .......................................................................... 11-26 11.5.1.7 Tubesheet Hole Refinishing..................................................................... 11-26 11.5.1.8 Installing New Tubes ............................................................................... 11-27 11.5.1.9 Expanding Tubes .................................................................................... 11-28 11.5.2 Rebundling...................................................................................................... 11-29 12 REFERENCES ................................................................................................................ 12-1 13 ACRONYMS .................................................................................................................... 13-1 14 GLOSSARY..................................................................................................................... 14-1 A SURVEY RESULTS ............................................................................................................A-1 B MECHANICAL TUBE CLEANING PROCEDURE...............................................................B-1 C TUBE PLUGGING PROCEDURES.....................................................................................C-1 D POP-OUT SUMMARY.........................................................................................................D-1

xix


LIST OF FIGURES Figure 2-1 Typical Steam Surface Condenser......................................................................... 2-1 Figure 2-2 Condenser Tube Arrangement............................................................................... 2-3 Figure 2-3 Removal of Non-Condensable Gas........................................................................ 2-4 Figure 2-4 Nuclear Power Plant Rankine Cycle with Moisture Separation and Reheat............ 2-4 Figure 2-5 Single-Compartment, Single-Pass, Transverse Flow Condenser ........................... 2-8 Figure 2-6 Single-Compartment, Two-Pass, Transverse Flow Condenser .............................. 2-9 Figure 2-7 Two-Compartment, Single-Pass, Transverse Flow, Series Design Condenser .... 2-10 Figure 2-8 Two-Compartment, Single-Pass, Axial Flow Condenser ...................................... 2-11 Figure 2-9 Three-Compartment, Single-Pass, Transverse Flow, Series Design Condenser..................................................................................................................... 2-12 Figure 2-10 Three-Compartment, Single-Pass, Axial Flow Condenser.................................. 2-12 Figure 2-11 Three-Compartment, Single-Pass, Axial Flow, Middle Waterbox Condenser ..... 2-13 Figure 2-12 Typical Steam Jet Air Ejector Stage Assembly................................................... 2-16 Figure 2-13 Single Element Steam Jet Air Ejector Configurations ......................................... 2-17 Figure 2-14 Typical Multi-Element Ejector Configurations ..................................................... 2-17 Figure 2-15 Parallel Trains of Air Ejector Equipment ............................................................. 2-18 Figure 2-16 Flat Port Type Liquid Ring Vacuum Pump.......................................................... 2-19 Figure 3-1 Condenser Diagnostics Flowchart.......................................................................... 3-3 Figure 3-2 Typical Curve of Air Binding in the Condenser ....................................................... 3-4 Figure 3-3 Condenser Pressure Response to Air In-Leakage Test.......................................... 3-5 Figure 3-4 Trouble-shooting Problems with LRVPs ............................................................... 3-10 Figure 4-1 Heat Rate Effect with Changing Condenser Pressure ............................................ 4-9 Figure 4-2 Typical Steam Side Instrumentation..................................................................... 4-12 Figure 4-3 Typical Water Side Instrumentation...................................................................... 4-13 Figure 4-4 Rotameter Type Flow Meter................................................................................. 4-14 Figure 5-1 Power Plant Intake Schematic ............................................................................... 5-5 Figure 5-2 Trash Rack and Trash Rake .................................................................................. 5-7 Figure 5-3 Typical Dual-Flow Traveling Screen Arrangement ................................................. 5-9 Figure 5-4 Debris Filter ......................................................................................................... 5-11 Figure 5-5 Typical Progression of Biofilm .............................................................................. 5-15 Figure 5-6 Biofilm Development Factors ............................................................................... 5-17 Figure 5-7 Chlorine Gas Feed Schematic ............................................................................. 5-28

xxi


Figure 5-8 EPRI Fouling Monitor ........................................................................................... 5-36 Figure 6-1 Braidwood Unit 1 Before Cleaning ......................................................................... 6-1 Figure 6-2 Braidwood Unit 1 After Cleaning ............................................................................ 6-2 Figure 6-3 Typical Ball Cleaning System................................................................................. 6-5 Figure 6-4 Older Design Ball Strainer System ......................................................................... 6-8 Figure 6-5 Newer Design Ball Strainer System ....................................................................... 6-9 Figure 6-6 Sponge Ball Recirculation System ....................................................................... 6-10 Figure 6-7 Typical Brush and Cage System .......................................................................... 6-12 Figure 6-8 Typical Arrangement for a Brush and Cage Tube Cleaning System..................... 6-13 Figure 6-9 Tube Cleaning Rocket.......................................................................................... 6-14 Figure 6-10 Tube Cleaning Rocket Injection System............................................................. 6-15 Figure 6-11 Typical Water Bristle Brushes ............................................................................ 6-16 Figure 6-12 Water Gun for Brushes and Scrapers................................................................. 6-16 Figure 6-13 Plastic Tube Scrapers ........................................................................................ 6-17 Figure 6-14 Metal Tube Scrapers.......................................................................................... 6-18 Figure 6-15 Mechanically Driven Brush................................................................................. 6-19 Figure 6-16 Typical Water Lance Heads ............................................................................... 6-19 Figure 7-1 Chart Recording of a Typical Leak Response ........................................................ 7-9 Figure 7-2 Turbine Shaft Gland Seal Housing ....................................................................... 7-10 Figure 7-3 Gas Analyzer ....................................................................................................... 7-11 Figure 7-4 Tracer Gas Release Device ................................................................................. 7-12 Figure 7-5 Schematic Diagram of SF6 Sampling System ....................................................... 7-13 Figure 7-6 Condenser Penetration Map ................................................................................ 7-20 Figure 7-7 Multisensor Probe ................................................................................................ 7-22 Figure 7-8 Schematic Diagram of the EPRI COLDS.............................................................. 7-35 Figure 8-1 Crevice Corrosion ................................................................................................ 8-11 Figure 8-2 Plug-Type Dezincification Magnified Cross-Sectional and Planar Views .............. 8-12 Figure 8-3 Inlet End Erosion-Corrosion ................................................................................. 8-14 Figure 8-4 Erosion-Corrosion From a Lodged Rock in a Tube .............................................. 8-15 Figure 8-5 Pitting Corrosion of 304 SS Tubes, Magnified Cross-Section and Planar Views ............................................................................................................................ 8-18 Figure 8-6 Stress Corrosion Cracking of Admiralty Brass, Magnified Cross-Section and Planar Views ................................................................................................................. 8-20 Figure 8-7 Air Bubble Turbulence in a Low-Pressure Zone ................................................... 8-28 Figure 8-8 (a) Poor Design for Tube Inlet Flow (b) Improved Design with Perforated Baffle Plate.................................................................................................................... 8-29 Figure 8-9 (a) Poor Design Tubesheet Inlet (b) Improved Design with Screen ...................... 8-30 Figure 9-1 ET Probe for Condenser Tube Testing................................................................. 9-16 Figure 9-2 ET Flowchart........................................................................................................ 9-22

xxii


Figure 10-1 Assorted Hammer-In Taper Plugs ...................................................................... 10-4 Figure 10-2 Two-Piece Hammer-In Plug ............................................................................... 10-5 Figure 10-3 Elastomer Plug................................................................................................... 10-6 Figure 10-4 Elastomer Condenser Plug Diagram .................................................................. 10-7 Figure 10-5 Mechanical Gripper-Type Plug, Shelf Condition ................................................. 10-8 Figure 10-6 Mechanical Gripper-Type Plug, Installed............................................................ 10-8 Figure 10-7 Mechanical Breakaway Plug .............................................................................. 10-9 Figure 10-8 Thimble-Style Plug ........................................................................................... 10-10 Figure 10-9 Plug Removal Tool........................................................................................... 10-15 Figure 10-10 Tube Insert..................................................................................................... 10-17 Figure 10-11 Improved Tube Insert ..................................................................................... 10-18 Figure 10-12 Sleeve Repair ................................................................................................ 10-20 Figure 10-13 Epoxy Tubesheet Cladding ............................................................................ 10-25 Figure 10-14 U Stainless Steel Tube Stake......................................................................... 10-26 Figure 10-15 Micarta Condenser Tube Stake...................................................................... 10-26 Figure 10-16 Cradle-Lock® Tube Stake .............................................................................. 10-27 Figure 10-17 Typical Condenser Tube Staking Pattern ....................................................... 10-28 Figure 11-1 High Performance Stainless Steel Installations .................................................. 11-8 Figure 11-2 High Performance Stainless Steel Water Usage ................................................ 11-9 Figure 11-3 High Performance Stainless Steels Problem Incidents..................................... 11-10 Figure 11-4 Typical Tube-to-Tubesheet Joints .................................................................... 11-17 Figure C-1 Atlantic Group Tube Installation for Flared and Straight Tube Ends......................C-1 Figure C-2 Bemark Associates K-Span Plug ..........................................................................C-2 Figure C-3 Conco High Confidence Tube Plug.......................................................................C-3 Figure C-4 Conco EX-3 Expanding Tube Plug .......................................................................C-4 Figure C-5 Conco EX-F Expanding Tube Plug .......................................................................C-4 Figure C-6 Conco FP Fiber Tube Plug ...................................................................................C-5 Figure C-7 Conco Pin Plug.....................................................................................................C-5 Figure C-8 Conco Pin and Collar Tube Plug...........................................................................C-6 Figure C-9 Expansion Seal Technologies VibraProof Condenser Plug...................................C-7 Figure C-10 Expansion Seal Technologies Condenser Perma Plug.......................................C-8 Figure C-11 Expansion Seal Technologies Expandable Thimble Plug ...................................C-9 Figure C-12 HEPCO Brass Condenser Tube Plug ...............................................................C-10

Figure C-13 Torq N’ Seal¥ Condenser Tube Plug ...............................................................C-11

Figure C-14 Torq N’ Seal¥ High Pressure Tube Plug ..........................................................C-11

xxiii


LIST OF TABLES Table 5-1 Commonly Used Oxidizing Biocides..................................................................... 5-20 Table 5-2 Typical Generic Non-Oxidizing Biocides............................................................... 5-21 Table 5-3 Technology-Based Regulations for Chlorine ........................................................ 5-24 Table 5-4 Chlorine-Based Oxidizing Biocides....................................................................... 5-30 Table 5-5 Bromine-Based Oxidizing Biocides and Biocide Precursors ................................. 5-33 Table 5-6 Application of Non-Oxidizing Biocides .................................................................. 5-34 Table 6-1 Typical Off-Line Cleaning Methods and Their Effectiveness................................. 6-15 Table 7-1 Air In-Leakage Limits.............................................................................................. 7-2 Table 8-1 Injuries from Hydrolaser Use .................................................................................. 8-2 Table 8-2 INPO SEE-IN Experience Information .................................................................... 8-3 Table 8-3 Licensee Event Reports for Main Condenser from 1984 to Present ....................... 8-5 Table 8-4 INPO Plant Events Database for Condensers ........................................................ 8-7 Table 8-5 OPEC Data for Condenser Tube Leak Events from 4/1998 to 6/2000 .................... 8-9 Table 8-6 Component Dealloying Mechanisms .................................................................... 8-13 Table 8-7 Suggested Critical Velocity Limits for Condenser Tube Alloys in Seawater .......... 8-15 Table 8-8 Galvanic Potential Differences for Typical Metals and Alloys................................ 8-17 Table 8-9 Condenser Failure Mechanisms and Affected Components ................................. 8-21 Table 8-10 Freshwater Condenser Materials and Galvanic Corrosion Protection Applications................................................................................................................... 8-24 Table 8-11 Salt/Brackish Water Condenser Materials and Galvanic Corrosion Protection Applications .................................................................................................. 8-25 Table 9-1 Failure Locations, Degradation Mechanisms, and PM Strategies ........................... 9-6 Table 9-2 PM Tasks and Their Degradation Mechanisms .................................................... 9-11 Table 10-1 Tube Plug Data ................................................................................................ 10-12 Table 10-2 Waterbox Tasks for Repair and Replacement .................................................. 10-30 Table 10-3 Tubesheet Tasks for Repair and Replacement................................................. 10-33 Table 11-1 High Performance Stainless Steel Tube Material ............................................... 11-7 Table 11-2 Summary of Pitting Corrosion Problems........................................................... 11-12 Table 11-3 Condenser Tube Material and Testing Specifications....................................... 11-15 Table 11-4 Condenser Tube Material Comparison ............................................................. 11-16 Table 11-5 Tubesheet Material Recommendations ............................................................ 11-21 Table 11-6 Condenser Shell and Waterbox Materials ........................................................ 11-22

xxv


Table 11-7 Tubesheet Hole Size Limits.............................................................................. 11-27 Table C-1 Installation Procedures for the Atlantic Group Brass and Fiber Jacketed Tube Plug.................................................................................................................................C-1 Table C-2 Installation Procedures for the Bemark Associates K-Span Plug ............................C-2 Table C-3 Installation Procedures for the Conco High Confidence Tube Plug .........................C-3 Table C-4 Installation Procedures for the Conco EX-3 and EX-4 Expanding Tube Plug..........C-4 Table C-5 Installation Procedures for the Conco EX-F Expanding Tube Plug .........................C-5 Table C-6 Installation Procedures for the Conco Fiber Tube Plug ...........................................C-5 Table C-7 Installation Procedures for the Conco Pin Plug .......................................................C-6 Table C-8 Installation Procedures for the Conco Pin and Collar Tube Plug.............................C-6 Table C-9 Installation Procedures for Expansion Seal Technologies VibraProof Condenser Plug...............................................................................................................C-7 Table C-10 Installation Procedures for Expansion Seal Technologies Condenser Perma Plug.................................................................................................................................C-9 Table C-11 Installation Procedures for Expansion Seal Technologies Expandable Thimble Plug .................................................................................................................C-10 Table C-12 Installation Procedures for the HEPCO Brass Condenser Tube Plugs................C-10 Table C-13 Installation Procedures for the Torq N’ SealTM Condenser Tube Plug ..................C-11 Table C-14 Installation Procedures for the Torq N’ Seal¥ High Pressure Tube Plug.............C-12

xxvi


1 INTRODUCTION

1.1

Background

With the age of steam condensers approaching twenty-five years for nuclear plants and forty years for fossil units, the cost of operating and maintaining this equipment is increasing. The frequency of testing, cleaning, repairs, and re-tubing efforts is increasing because of the age and condition of the equipment. In addition, there are performance losses associated with biofouling and air/water in-leakage. Long-term reliability of the condensers is important to maintain load and performance in power plants. In 1999, EPRI NMAC (Nuclear Maintenance Application Center) sent a survey to their member nuclear plants requesting input on equipment that might need NMAC attention. Issues with condensers were characterized by the words, “air in-leakage, baffles, and tube integrity.” The responses were about even as to whether or not the condenser equipment needed further attention. The topic of condensers was again discussed at the August 2000 meeting of the NMAC Site Coordinators with the following issues identified: x

Tubesheet

x

Leak detection

x

Tubing material issues

x

Plugging issues

x

Cleaning tubes

x

Mechanical issues with shields and baffles

x

Vibration

x

General inspection and testing off-line

x

Testing off-line

From this input, EPRI decided to develop a condenser guide that would emphasize reliability, performance, and maintenance practices. Several excellent EPRI guides were used in the development of this guide. Some of these guides were: x

Recommended Practices for Operating and Maintaining Steam Surface Condensers, CS-5235. July 1987.

x

Condenser Microfouling Control Handbook, TR-102507. April 1993.

x

High-Reliability Condenser Application Study, TR-102922. November 1993. 1-1

EPRI Licensed Material Introduction

x

ABC’s of Condenser Technology, TR-104512. August 1994.

x

Condenser In-Leakage Guidelines, TR-112819. January 2000.

1.2

Approach

A statement of work was developed and sent to EPRI member nuclear and fossil plants and vendors for input. A technical advisory group (TAG), composed of seven nuclear utility representatives, four vendors, one EPRI Plant Support Engineering Project Manager and one member from the Heat Exchanger Institute (HEI), provided input and a detailed review of the guide. This guide updates the NMAC ABCs of Condenser Technology guide and incorporates that information into this document. This guide is designed to cover the condenser shell, waterbox, tubesheet, and tube bundles. Some information on the air-removal equipment is included because air and water in-leakage is covered. It is not the intent of this guide to cover feedwater heaters, condenser neck seals, extraction lines, and expansion joints, intake piping, the circulating water pump, or hotwell pumps. Parts of the cooling water intake are covered as they relate to fouling. This guide was developed for and funded by the nuclear plants. However, the design, operation, and maintenance of both nuclear and fossil condensers are very similar. It is intended that this guide apply to both types of plants. A survey was sent to the EPRI member condenser contacts in the nuclear and fossil plants. The survey requested information on the design, materials, cleaning practices, chemical water treatment, cathodic protection, etc. of each plant. The intent of the survey was to provide an information source for plant personnel with similarly designed plants and similar operation/maintenance issues. The survey results are tabulated in Appendix A.

1.3

Guide Organization

This condenser guide is organized into the following sections: 1. The Introduction section includes Background, Approach, Guide Organization, and PopOuts. 2. The Tutorial section includes descriptions for Operation, Rankine Cycle, Secondary Functions, Types, and Components. 3. The Trouble-Shooting section includes Increased Condenser Pressure, Air-Binding Problems, Air-Removal Equipment Problems, and Excessive Air In-Leakage. 4. The Performance section includes Heat Transfer, Condensing Duty, Heat Transfer Coefficient, HEI Method, ASME Method, Turbine Blade Effects, Performance Monitoring, Performance Software Tools, and Instrumentation.

1-2


5. The Fouling section includes Macrofouling, Macrofouling Control Technologies, Microfouling, Microfouling Chemical Treatment, Fouling Monitor, and Targeted Chlorination with Fixed Nozzles. 6. The Cleaning section includes Mechanical On-Line Cleaning Systems, Mechanical Off-Line Cleaning Systems, and Chemical Cleaning. 7. The Air/Water In-Leakage section includes Air In-Leakage Effects, Air In-Leakage Detection Methods, Correcting Air In-Leakage, Water In-Leakage Effects, Water In-Leakage Detection Methods, and Correcting Water In-Leakage. 8. The Failure Modes section includes Failure Data, Failure Mechanisms, and General Corrosion Prevention Practices. 9. The Condition-Based Maintenance section includes Records, Periodic Inspections, Preventive Maintenance, and Non-Destructive Examination. 10. The Maintenance Repairs section includes Plugging Tubes, Tube Inserts, Tube Sleeves, Tube End Coatings, Full Length Tube Liners, Full length Tube Coatings, Re-Expanding the Tubeto-Tubesheet Joint, Coating of Tubesheet, Tube Staking for Vibration, Waterbox Repairs, Tubesheet Repairs, Tube Pulling, and Miscellaneous Repairs. 11. The Remaining Life, Materials, and Constructability section includes Remaining Life Assessment, Tube Material Selection, Tubesheet Joints and Material Selection, Waterbox and Shell Materials, and Constructability Issues (Retubing and Rebundling). 12. References 13. Acronyms 14. Glossary 15. The Appendix section includes the Nuclear and Fossil Plant Survey Results, a Mechanical Tube Cleaning Procedure, Tube Plugging Procedures, and a Pop-Out Summary. Because many sources of information were used in the compilation of this guide, it was decided that a reference system would be used for the appropriate sections. Reference numbers in brackets, [#], are used at the beginning of certain sections and after the titles on tables and figures to denote the source of the majority of information in that section. The reference numbers and corresponding reference sources are listed in the Reference section of the guide.

1.4

Pop-Outs

Throughout this guide, key information is summarized in Pop-Outs. Pop-Outs are bold lettered boxes, which succinctly re-state information covered in detail in the surrounding text, making the key point easier to locate.

1-3


The primary intent of a pop-out is to emphasize information that will allow individuals to act for the benefit of their plant. Utility and EPRI personnel who reviewed and prepared this guide selected the information included in these pop-outs. The pop-outs are organized according to three categories: O&M Costs, Technical, and Human Performance. Each category has an identifying icon to draw attention to it when quickly reviewing the guide. The pop-outs are shown as follows: Key O&M Cost Point Emphasizes information that will result in overall reduced costs and/or increase in revenue through additional or restored energy production.

Key Technical Point Targets information that will lead to improved equipment reliability.

Key Human Performance Point Denotes information that requires personnel action or consideration in order to prevent personal injury, equipment damage and/or improve the efficiency and effectiveness of the task. The Pop-Out Summary section of this guide contains a listing of all key points in each category. The listing re-states each key point and provides a reference to its location in the body of the report. By reviewing this listing, users of this guide can determine if they have taken advantage of key information that the writers of this guide believe would benefit their plants.

1-4


2 TUTORIAL

2.1

Condenser Operation

A condenser is a large heat exchanger of the shell and tube type. A typical steam surface condenser is shown in Figure 2-1. Cooling water enters through the waterbox, through the tubesheet and into the tubes. The shell side of the condenser receives steam from the lowpressure turbine exhaust. The steam is cooled to a liquid by passing over the tubes where the cooling water is circulated. Heat is transferred from the steam to the cooling water. For the steam to be condensed to water, the amount of heat removed must at least be equal to the latent heat of vaporization. Latent heat will depend on the pressure in the condenser and the quality of exhaust steam.

Figure 2-1 Typical Steam Surface Condenser (courtesy of Senior Engineering Co.)

2-1

EPRI Licensed Material Tutorial

An open circulating water system consists of fresh, brackish or saltwater pumped into the condenser from a river, lake, or ocean and returned to the same body of water. The circulating water might pass through trash rakes, a trash rack, and traveling screens before being pumped by the circulating water pumps into the condenser. This heated circulating water is then returned to the river, lake, or ocean downstream of the inlet to the condenser. Federal and state environmental restrictions apply to the temperature and composition of the water returned to the river, lake, or ocean. The flow path is known as an open circulating, cooling water system that will be referred to as a once-through system in this guide. An open recirculating, cooling water system uses a pond or cooling tower where the circulating water is supplied to the condenser through pumps or is gravity fed. The circulating water goes through the condenser and is returned to the pond or cooling tower. Heat from the circulating water is released to the atmosphere and surrounding water. The water is then returned to the condenser to start the cycle again. Makeup water is provided for any evaporation or leakage losses. Within the condenser shell are several components that use the condenser as a place to release heat. Various steam vents and drains are piped to the condenser. In some condensers, the lowpressure feedwater heaters are mounted in the side of the shell. In this way, the extraction lines from the low-pressure turbines are piped within the shell to the feedwater heaters to reduce pressure losses. The exhaust from the feedwater pump turbine is also piped to the condenser shell. A vacuum is produced in the condenser by the condensation process and the specific volume change from steam to a liquid. A low condenser vacuum corresponds to a low steam saturation temperature. The total work done by steam flow through the turbine is proportional to the difference between the temperature of steam entering the turbine and the saturation temperature in the condenser. Therefore, the lower the saturation temperature, the more work that is done by the steam in the turbine. The more work that is done in the turbine, the greater the thermal efficiency and output of the turbine. The vacuum established is typically between 1 and 3.5 in. Hg absolute (2.5 and 9 cm Hg). This corresponds to 29 and 26 in. Hg gauge (73 to 66 cm Hg). Because condensers handle large quantities of steam at low, sub-atmospheric pressure, the volumetric flow is high. As a result, the condenser tube arrangement must be opened rather than compacted in order to allow steam flow into the inner region of the tube bundle. A typical tube arrangement is shown in Figure 2-2. The tube pattern and shell volume is designed to minimize the steam side pressure drop. A cruciform region in the middle of the bundle is void of tubes and forms a passageway to the circulating water inlet end of the condenser. This is to vent noncondensable gases that can accumulate during condensation of the steam. This is one design and condenser manufacturers locate the non-condensable vents based on a number of arrangements and bundle geometry factors.

2-2


Figure 2-2 Condenser Tube Arrangement [1]

Condensers must continually vent non-condensable gases to prevent air binding and the loss of heat transfer capability. Sources of non-condensable gases come from air in-leakage. In PWRs, ammonia from oxygen-scavenging chemicals is a source of non-condensable gas. In BWRs, oxygen and hydrogen are generated in the reactor vessel and mix with the main steam. Figure 2-3 shows how non-condensable gas flows within and out of a condenser. Noncondensable gas has a tendency to flow to the coldest area. This area is typically the circulating water inlet region of the condenser. This tendency occurs because the partial pressure of the condensing steam is lowest in the cold region. Having the air outlet at the circulating water inlet might not be possible with all condenser bundle designs. Steam jet air ejectors and/or vacuum pumps establish a vacuum in the condenser before start-up and pull non-condensable gas with some steam from the condenser during operation.

2-3


Figure 2-3 Removal of Non-Condensable Gas [1]

2.2

Rankine Cycle [2]

Figure 2-4 shows the simplified model of the nuclear steam cycle.

Figure 2-4 Nuclear Power Plant Rankine Cycle with Moisture Separation and Reheat [2]

2-4


The processes shown in the temperature-entropy diagram are outlined below. From: x

Point 1 to point 2 is the addition of heat to the subcooled water in the steam generator.

x

Point 2 to point 3 is the heat addition to the saturated water, followed by superheating of the steam.

x

Point 3 to point 4 is the expansion of the steam through the high-pressure turbine.

x

Point 4 to point 5 is the moisture removal in the Moisture Separator Reheater.

x

Point 5 to point 6 is the heat addition from the Moisture Separator Reheater.

x

Point 6 to point 7 is the expansion of the steam through the low-pressure turbine.

x

Point 7 to point 1 is the heat removal in the condenser. It is necessary to condense the steam to a liquid to pump the condensate through the feedwater heaters and then to the reactor/boiler.

One of the purposes of the main condenser is to condense low-pressure turbine exhaust steam to enable maximum expansion of steam in the low-pressure turbine. An increase in condenser pressure results in an increase in heat rate. The lower the condenser pressure and temperature, the lower the amount of heat rejected. This lowering of heat rejected, shown by the shaded area in Figure 2-4, provides more available energy for expansion through the turbine (represented by the line from point 6 to point 7). The heat added is not increased.

2.3

Condenser Secondary Functions [3]

The primary function of a condenser is to condense steam from the exhaust of the steam turbine. The secondary functions include: x

Removing dissolved non-condensable gases from the condensate. Concentration of a dissolved gas in a solution is directly proportional to the partial pressure of that gas in the free space above the liquid. Deaeration or removal of the dissolved oxygen from water takes place by the reduction of partial pressure of air in the surrounding atmosphere. Condensate is then reheated to a temperature above the point that oxygen entrainment will occur. This can be accomplished by using steam spargers or bubbling steam through the hotwell. Chemical compounds are added to the feedwater to remove the last traces of oxygen. Oxygen and other non-condensable gases released in the condenser are then removed through the steam jet air ejectors or vacuum pumps.

x

Conserving the condensate for re-use as feedwater. The base of the condenser, or hotwell, serves as a holding tank for the condensate. The hotwell provides suction to the condensate pumps that return the condensate to the feedwater system. In this way, the condensate is saved and returned to the system. For a BWR unit, the main steam bypasses the turbine after a unit trip and enters the condenser. Pressure reduction of the main steam before entering the condenser, and dispersion of flow in the condenser, might be accomplished by a series of orificed plates or pipes. In addition, the short-lived radionuclides in the steam decay in the condenser. When the condensate is pumped to the feedwater system, the radiation level is decreased. 2-5


x

Providing a leak-tight barrier between the high-grade condensate and untreated cooling water. The condenser tubes and tubesheets act as barriers between the relatively impure cooling water and the high-grade condensate. Due to the vacuum inside the condenser, any leakage will cause contamination of the condensate with the cooling water. This can lead to an increased corrosion rate in the steam generator/reactor/boiler. Though prevention of circulating water in-leakage is imperative in all cooling water systems, it becomes critical where brackish or saltwater is used for cooling. A leakage of 0.1 gallons per minute (gpm) (23 liter/hr) can be unacceptable and cause significant corrosion.

x

Providing a leak-tight barrier against air ingress and preventing excess backpressure on the turbine. The ingress of air and other non-condensables into the condenser shell can affect thermal performance. The air-removal systems and their auxiliary equipment routinely remove these gases. When excessive amounts of air are in the shell side, then the condenser pressure is increased. The effect of increased condenser pressure lowers the thermal efficiency of the turbine. In addition, high dissolved oxygen concentrations in the condensate can increase the rate of corrosion in the steam generator/reactor/boiler.

x

Serving as a drain receptacle for condensate. Because the condenser is the lowest pressure point in a steam cycle, it is the most logical collection point for various condensate vents and drains. The incoming vents and drains are usually located at a higher elevation above the tube bundles in a condenser. By the time the fluid reaches the hotwell, it is sufficiently heated and deaerated.

x

Providing a convenient place for feedwater makeup. The cold makeup water discharge line is located above the tube bundles. The make-up fluid is heated and deaerated before it reaches the hotwell.

x

Maintains vacuum for the discharge of the turbine blades. The thermal efficiency of the turbine expansion process depends on the existence of a vacuum at the low-pressure turbine outlet.

2.4

Condenser Types [3]

Several types of condensers are used by the utility industry. The choice depends on the design of the cooling water system, desired temperature rise, plant and turbine configuration, and cooling water system optimization. The condenser for any given steam turbine-generator might be designed with one, two, or three compartments. The water flow path both within a compartment and between compartments is also site-specific. Condensers are configured in several ways. The classifications are: x

The number of compartments, usually one compartment for each set of turbine two-flow exhausts

x

The number of tube passes, one or two

x

Orientation of the condenser tubes, transverse or parallel to the axis of the turbine

x

Whether the circulating water flows in parallel through each condenser shell or in series through each shell

2-6


The following are different types of condensers and their configurations. 2.4.1 Single-Compartment, Single-Pass, Transverse Flow Condenser Figure 2-5a shows the water path configuration for a condenser with a single compartment. Generally, the cooling tubes are mounted perpendicular to the turbine axis. This is called a transverse tube arrangement. Tubes in this design are shorter in length (approximately 50 feet) (15.2 meters). Many of the smaller condensers of this configuration have one inlet and one outlet waterbox (Figure 2-5b). With one waterbox, the unit must be taken out of service before access to the tubes is possible. On larger units, a divided waterbox is provided (Figure 2-5c) where access to one box at a time is possible with the unit on-line at a reduced load.

2-7


Figure 2-5 Single-Compartment, Single-Pass, Transverse Flow Condenser [3]

2.4.2 Single-Compartment, Two-Pass, Transverse Flow Condenser Figure 2-6 shows a condenser with a single compartment and two passes. In this design, there are two tube bundles, one on top of the other. Circulating water flows through the upper waterbox into the top tube bundle, reverses direction by 180 degrees and flows back through the lower tube bundle, and exits through the lower waterbox. This style allows higher flow velocity and temperature rise.

2-8


Key O&M Cost Point Two-pass condensers are selected when the cooling water is a premium quantity, installation space is restricted, or the plant layout dictates that the inlet and outlet must be at the same end of the condenser. In plants with cooling towers, a two-pass condenser can reduce the size and, therefore, the cost of the cooling tower.

Figure 2-6 Single-Compartment, Two-Pass, Transverse Flow Condenser [3]

2.4.3 Two-Compartment, Single-Pass, Transverse Flow, Parallel Design Condenser Two compartment condensers are designed in several configurations. Each compartment can be a single-pass type with the compartments piped in parallel. This gives a common water inlet temperature. Assuming the exhaust flow is equally divided between the compartments, the backpressure in both compartments will be approximately the same. 2.4.4 Two-Compartment, Single-Pass, Transverse Flow, Series Design Condensers The two compartments might be piped in series as shown in Figure 2-7 for a fossil unit. The water leaving the first condenser compartment is connected to the inlet of the second compartment. The inlet and outlet water temperatures and backpressures for each compartment will be different. The first shell will receive the coldest cooling water and, therefore, will have the lowest pressure and the lowest saturation temperature. Condensate from the first compartment is pumped to the second compartment. This results in a condensate temperature as high as in a single-pressure condenser. 2-9


Figure 2-7 Two-Compartment, Single-Pass, Transverse Flow, Series Design Condenser [3]

2.4.5 Two-Compartment, Single-Pass, Axial Flow Condenser Figure 2-8 shows a two-compartment condenser where the tube bundles run parallel to the turbine axis as one continuous flow path. This longitudinal design requires fewer waterboxes and the initial capital cost can be less. The length of tubes in the longitudinal design can be 70 feet (21.3 meters) long. A large space is needed in the plant layout for cleaning and removal of tubes for maintenance.

2-10


Figure 2-8 Two-Compartment, Single-Pass, Axial Flow Condenser [3]

2.4.6 Three-Compartment, Single-Pass, Transverse Flow, Parallel Design Condenser Three-compartment condensers consist of several single compartment condensers of the oncethrough type arranged in parallel. Most often these compartments have divided waterboxes. 2.4.7 Three-Compartment, Single-Pass, Transverse Flow, Series Design Condenser Figure 2-9 shows a three-compartment condenser arranged in series. The backpressures and inlet and outlet water temperatures in each compartment are different.

2-11


Figure 2-9 Three-Compartment, Single-Pass, Transverse Flow, Series Design Condenser [3]

2.4.8 Three-Compartment, Single-Pass, Axial Flow Condenser Figure 2-10 shows a three-compartment, single-pass, axial flow design. The length of tubes in the longitudinal design can be 100 feet (30.5 meters) long. A large space is needed in the plant layout for cleaning and removal of tubes for maintenance.

Figure 2-10 Three-Compartment, Single-Pass, Axial Flow Condenser [3]

2-12


2.4.9 Three-Compartment, Single-Pass, Axial Flow, Middle Waterbox Condenser An alternative design is to locate a waterbox in the center of the middle compartment. In this arrangement, the inlet tubes run from the inlet waterbox through the first compartment and to a waterbox in the center of the second compartment. A separate tube bundle runs from the center waterbox to the third compartment and to the outlet waterbox. This is shown in Figure 2-11.

Figure 2-11 Three-Compartment, Single-Pass, Axial Flow, Middle Waterbox Condenser [3]

Key O&M Cost Point Generally, multi-compartment condensers lower average backpressure in the low-pressure turbine without a significant decrease in the temperature of the condensate leaving the hotwell. The lower condenser backpressure means increased turbine efficiency.

2.5

Condenser Components [4]

A general diagram showing the condenser components was shown in Figure 2-1. The major components are: x

Shell

x

Hotwell

x

Waterbox

x

Tubesheet

x

Tubes

x

Air-removal equipment

2-13


2.5.1 Condenser Shell Key Technical Point The condenser shell is designed to withstand up to 15 psig (1 kg/cm²) and, therefore, is not governed by the ASME Pressure Vessel Code. The only design code applicable to condensers in the utility industry is the Heat Exchange Institute (HEI) standards. The design pressure of the shell is 30 inches Hg (76.2 cm Hg) vacuum and is suitable for an emergency internal pressure of 15 psig (1 kg/cm²). The shell is constructed of carbon or stainless steel plates welded together. Shell pressure boundary plates, support plates, and welds should have a 1/32-inch (794 nm) corrosion allowance on each side exposed to steam/water in the condenser. The shell is hydrostatically tested after field assembly. The shell might be joined to the turbine exhaust casing by an expansion joint. The joint might be a metal bellows or rubberized fabric joint. Some design condensers might not have an expansion joint, that is, spring mounted or some axial designs. 2.5.2 Hotwell The base of the condenser is a reservoir for the condensate and is called the hotwell. The hotwell is made of the same material as the shell and is an integral part of or is connected to the bottom of the shell. The hotwell is designed to have a minimum available volume sufficient to contain all of the condensate produced in the condenser in a period of one minute under conditions of maximum steam load. Suction is provided from the hotwell to the condensate pumps to deliver the condensate into the feedwater system. Because the hotwell is the lowest pressure point in the steam cycle, it is the collection point for various steam vents and drains. 2.5.3 Waterbox Waterboxes are typically constructed of carbon steel or cast iron but can be made of stainless steel, copper nickel, or titanium. Cast iron is more resistant to corrosion but cannot be easily repaired. Internals of the waterbox are generally coated or cathodically protected to minimize corrosion. The waterbox is designed to the pressure of the circulating water system. The critical design aspect of a waterbox is its access. There should be one manway at the bottom of the box and one at the top. Two manways at the top are preferable. Waterboxes are either bolted or welded to the condenser with the tubesheet between the waterbox and condenser flange. 2.5.4 Tubesheet The tubesheet is a non-rigid structural member of the condenser. The tubesheet does not support the total load of waterbox pressure, the waterbox, or water in the waterbox. Condenser tubes share this load with the tubesheet. The primary function of the tube-to-tubesheet joint is to 2-14


prevent leakage of cooling water into the condensate. Tube-to-tubesheet joint leakage tends to be small and difficult to locate. Tubesheets can be constructed of copper nickel, Muntz metal, aluminum bronze, carbon steel, stainless steel, titanium, or carbon steel clad with stainless steel or titanium. 2.5.5 Tubes Alloy steel condenser tubes are manufactured by forming alloy steel strips and then welding them with high frequency welding equipment. The tubes might or might not be scarfed (machining an angled surface in preparation for welding), depending on the specifications. Scarfing tubes is not an option for titanium tubes. Copper-alloy tubes can be seamless (using the extrusion process) or welded. Tubes can be made of titanium, Al-6X, Sea-cure, Al 29-4C, NuMonit, stainless steel, copper nickel, aluminum bronze, and admiralty brass. Key Technical Point In the air-removal section of the tube bundle, the tubes are exposed to an oxygenated, ammonia-rich environment. This environment promotes condensate corrosion (grooving) in copper-alloy tube materials. For this reason, the tube materials in this section are made from a more corrosionresistant alloy such as stainless steel. For more information on tube material refer to Section 11.2. 2.5.6 Air-Removal Equipment [3] An adequate air-removal and monitoring system is essential for the removal of non-condensable gases from the condenser. The air-removal section is normally located toward the bottom of, or deep within, the tube bundles where the condensate and water vapor temperature tends to be lower. There, the vapor becomes subcooled with respect to the saturation temperature corresponding to the pressure of the vapor. It is a region of tubes surrounded by a shroud (roof and side panels) to protect the tubes from being heated by descending condensate and steam. This shrouded region is connected to an external exhauster by means of an air-removal line. The lower tube temperature and associated vapor subcooling tends to cool any air or other noncondensables present. This reduces their specific volume, condenses the extracted water vapor, and concentrates the gases within the protected area. These actions create a scavenging process to remove non-condensables from the region under the shroud. The exhauster located at the other end of the air-removal conduit subsequently removes the gases. The equipment used to remove gases and create a vacuum is the steam jet air ejector and/or vacuum pump. Section 2.5.6.1 covers the steam jet air ejector and section 2.5.6.2 covers the liquid ring vacuum pump.

2-15


2.5.6.1

Steam Jet Air Ejector

The operation of a steam-driven air ejector uses the viscous drag of a high-velocity steam jet for the ejection of air and other non-condensables from a condenser compartment. The steam jet flows through a chamber where it entrains the air and any gases adjacent to the surface of the jet. The kinetic energy of the resulting mixture is then converted to pressure energy by being passed through a diverging cone or diffuser. The resulting increase in pressure enables the mixture to be discharged against a pressure that is higher than that of the entraining chamber. The main steam is throttled and connected to the nozzle that is on the same axis as the mixing section and diffuser. The basic construction of a steam jet ejector is shown in Figure 2-12.

Figure 2-12 Typical Steam Jet Air Ejector Stage Assembly [3]

A variety of air ejector system configurations exist. Some of the configurations are single element, single stage, condensing or single element, two stage condensing or non-condensing, two element, two stage non-condensing, and parallel train. It might be necessary to use two or three ejectors in series to obtain the desired vacuum. In the condensing designs, an intercooler is located between the ejectors to condense the steam leaving the preceding ejector. These coolers lower the temperature of the steam leaving the ejector stage and reduce the volume before entering the next stage. The aftercooler is used to condense the steam before leaving to the vent system. Figures 2-13, 2-14, and 2-15 show the different ejector configurations.

2-16


Figure 2-13 Single Element Steam Jet Air Ejector Configurations [3]

Figure 2-14 Typical Multi-Element Ejector Configurations [3]

2-17


Figure 2-15 Parallel Trains of Air Ejector Equipment [3]

2.5.6.2

Vacuum Pump

Liquid ring vacuum pumps are the most common form of mechanical pump used in air-removal systems for steam surface condensers. The liquid ring vacuum pump is a rotary, positive displacement pump using a liquid as the principal element in gas compression. It is not unusual 2-18


for more than one liquid ring vacuum pump system connected in parallel to be used. This allows the air-removal capacity to be adjusted, especially during low load operation or low condenser circulating water inlet temperatures. It also permits maintenance to be conducted without taking the unit out of service. See Figure 2-16 for an illustration of a liquid ring vacuum pump.

Figure 2-16 Flat Port Type Liquid Ring Vacuum Pump [3]

2-19


3 TROUBLE-SHOOTING

This section on trouble-shooting condenser problems deals with the operating conditions of increased condenser pressure, air binding, and air-removal equipment problems. The detection and location of a leaking tube is covered in Section 7.5 of this report. Excessive air in-leakage is covered in Section 7.2 of this report.

3.1

Increased Condenser Pressure [3]

Condenser pressure is the pressure at the top of the first row of tubes. Turbine backpressure is the pressure at the turbine/condenser flange. These pressures and temperatures might not be equal due to the condenser neck design. In most discussions, the condenser pressure and turbine backpressure are considered the same thing. Turbine backpressure is important because it affects the final stage, turbine blade performance. Two indications that the condenser might not be performing in accordance with its design, given the current cooling water inlet temperature and flow rate, are: x

High Condenser Pressure. The problem resulting from high pressure is that additional fuel is needed to produce the design load or else the heat rate has become too high, requiring a decrease in steam generation. Another problem might be that the designed unit megawatt load cannot be generated because the condenser backpressure has reached its allowable limit.

x

Increased Level of Dissolved Oxygen (DO). The problem resulting from high dissolved oxygen is the need for additional water treatment and the increased chance for corrosion.

Other indicating parameters that impact the shell side of the condenser include: x

Terminal temperature difference (TTD) (the difference between the steam temperature and the outlet cooling water temperature)

x

Changes in waterbox pressure drop

x

Abrupt step change in outlet or return waterbox temperature profile

x

Increase in condensate subcooling

x

Measured increase in heat rate

x

Measured air in-leakage

All of these parameters should be monitored for operating limits and in association with one another. Some of the above parameters are also affected by water side conditions and will be included in the following discussion. 3-1

EPRI Licensed Material Trouble-Shooting

Figure 3-1 shows a diagnostic flowchart for high condenser pressure. The following discussion details utilization of the chart to determine the cause of the problems. Starting with the right hand side of the chart, an increase in condenser pressure associated with an increase in the TTD, an increase in the cooling water 'T, and an increase in the cooling water 'P will point to a vacuum pump priming problem with low waterbox level and macrofouling with normal waterbox level. An increase in condenser pressure, an increase in the TTD, a normal cooling water 'T, and a high oxygen level, point to air binding and a high hotwell level. If the oxygen level is normal, then microfouling could be the problem. For the causes of air binding, the air-removal flow rate can be low, normal, or high. For a low flow rate, the air-removal problem can be caused by inadequate design, poor performance, low load operation, low inlet water temperature, and/or air-removal equipment problems. For a normal air-removal flow rate, there can be air in-leakage below the hotwell caused by condenser pump seals, hotwell manway gaskets/flanges, and strainer spool piece problems or high dissolved oxygen levels in the condensate lines. For a high air-removal flow rate, there can be air in-leakage above the hotwell caused by turbine seals, expansion joints, gaskets/flanges, condenser shell weld leaks, and so on. For the left-hand side of the chart, a high condenser pressure, a normal TTD, and normal cooling water temperature difference indicates a high inlet water temperature. A high temperature difference indicates low cooling water flow. If the head on the cooling water pump is high, then there is increased cooling water system resistance. This can come from water side air binding, inlet/outlet valve problems, and macrofouling of the cooling water pipe. If the cooling water pump head is normal, then the cooling water pump motor amps can be examined. If the motor amps are decreasing, then the pump might be experiencing wear or corrosion on the pump impeller and casing. If the motor amps are fluctuating, then the pump can be cavitating. Cavitation can be caused by silt or macrofouling in the intake or the intake water level might be too low. If the motor amps are increasing, then there might be other pump or casing damage. Key Technical Point Backpressures lower than design tend to improve heat rate. Therefore, lower backpressures are desirable. However, the backpressure should not be so low that it is the cause of unnecessary condensate subcooling (see the discussion in Section 4.1.1). The upper limit on backpressure is given by the turbine manufacturer, typically in the 4.5 to 5.0 in. HgA (11.4 to 12.7 cm Hg) range.

3-2


Figure 3-1 Condenser Diagnostics Flowchart (Source: Han Moy, Consolidated Edison of New York)

3.2

Air Binding Problems [1]

Air binding [5] is a term used to describe the insulating effect of air on condenser tubes when the space between the tubes is filled with air. Although this condition can occur in many areas, it is primarily found in the air-removal zone when the air in-leakage rate exceeds the capacity of the air-removal equipment. The possible causes of air binding are: x

Steam bypassing the air cooler zone of the condenser. When the steam bypasses the airremoval zone through cracks in the piping or the seal plates, the steam leaking into the airremoval piping reduces the amount of air removed by displacing air. This raises the vacuum pump seal water temperature.

x

Insufficient capacity of air-removal equipment. This can be due to equipment wear, equipment under-sizing, or high seal water temperature.

x

Design limitations of dual pressure condensers. If one vacuum pump/steam jet air ejector is operating or the air-removal sections of the low-pressure and high-pressure condensers are tied together, then air binding can occur. Removal of the air in the high-pressure condenser displaces the air that could have been removed from the low-pressure condenser with higher pressure steam.

x

High air in-leakage. With a high concentration of air in the steam entering the condenser, a pressure drop exists between the outer tubes and the air-removal section. This might result in the accumulation of air outside the air-removal zone. In addition, high air in-leakage will increase the pressure drop in the suction piping of the air-removal equipment, resulting in a 3-3


further decrease in air-removal equipment capacity. The pressure drop between the condenser shell pressure and the pressure at the suction of the air-removal equipment can be more than 1 inch of mercury (1.5 cm Hg). Several methods that can be used to determine if air binding is occurring are: x

System operational changes. Baseline data is collected with normal vacuum pump operation. An additional vacuum pump is placed in service while monitoring condenser pressure, load, and circulating water inlet temperature. If the addition of another vacuum pump results in a decrease in condenser pressure, while the other factors remain constant, then the condenser is air-bound.

x

Loads versus pressure curves. The condenser pressure, circulating water inlet temperature, and load can be monitored over a period of time when load reductions are planned or can be scheduled. The condenser pressure should drop with decreasing load. It drops less rapidly if the condenser is air-bound. A curve demonstrating how an air-bound condenser behaves at low load is shown in Figure 3-2.

Figure 3-2 Typical Curve of Air Binding in the Condenser [1]

x

3-4

Air in-leakage rate versus pressure. While holding the load constant with air-removal equipment in service, a measured rate of air, increased in steps, can be added to the condenser. If the initial step of introducing air does not cause the condenser pressure to rise, then the condenser is not air-bound. Figure 3-3 shows a typical condenser pressure response to controlled air in-leakage when the condenser is air-bound and when it is not. Caution should be taken when using this method because recovery can be difficult and there is the potential to lose control of the air in-leakage.


Figure 3-3 Condenser Pressure Response to Air In-Leakage Test [1]

x

Outlet Temperature Stratification. A grid of temperature detectors can be installed at the outlet of the condenser to identify regions of low heat transfer. Because air binding prevents the entrance of steam into the regions of the tube bundle where air binding is occurring, the circulating water temperature rise in the air-bound regions is reduced. This method can be costly to install and maintain.

3.3

Air-Removal Equipment Problems [3]

The information in Sections 3.3.1 through 3.3.5 deals with trouble-shooting problems with the steam jet air ejectors. Section 3.3.6 and 3.3.7 concentrate on problems with the liquid ring vacuum pumps (LRVPs). 3.3.1 Poor Vacuum Poor condenser vacuum caused by problems with the steam jet air ejectors is indicated by one or more of the following conditions: 3-5


x

Low steam pressure. Each ejector nozzle is specially designed for the steam pressure specified for the application. If the pressure is less than design, the system cannot achieve the desired vacuum, and the following should be checked: 1. Compare the steam pressure at the inlet to the ejector steam chest with the rated pressure. If it is not possible to increase the supply steam pressure, check with the manufacturer for possible nozzle changes to allow for the lower steam pressure. 2. Check whether there are any obstructions in the steam supply system that might be causing the low pressure. 3. Check whether any pressure-reducing valve in the system is functioning incorrectly.

x

Superheated steam. Mass flow through a given nozzle is less for superheated than for saturated steam. Note that saturated steam passing through a pressure-reducing valve will become superheated. Steam supplied to a steam jet air ejector should never contain moisture because this can cause erosion as well as performance problems. If the motive steam is not dry saturated but is superheated, the ejector manufacturer should be alerted. The design of the steam jet air ejector can be adjusted to meet this steam condition.

x

Clogged nozzle orifices. Small nozzles designed for high steam pressures are more apt to become clogged than those designed for lower pressures. Properly designed steam ejectors will allow the steam nozzle to be cleaned in place. An alternative method is to remove the entire steam chest assembly. Then remove the plug located on the steam chest and blow out any chips or scale from the nozzle end.

x

Total condenser air in-leakage. Check the main condenser air in-leakage with the probe provided on the discharge of the after-cooler for a condensing ejector system. If air leakage is excessive, check the vacuum system for tightness.

x

Loop seal drain too short. Condensate drain lines and loop seals must be properly designed to prevent short-circuiting of the air between the main turbine condenser and the inter-cooler for a condensing ejector system configuration.

x

Excessive discharge pressure at ejector atmospheric stage. Excessive discharge pressure on any ejector stage can cause unstable operation. Starting at the final ejector stage, discharge pressures should be checked and compared with design values.

x

Poor main condenser operation. When condenser equipment has been in operation for extended periods of time, deterioration in performance is often attributed to the ejector vacuum system. However, the main turbine condenser might itself be the source of the problem. Some of the possible causes include high cooling water temperature, insufficient cooling water flow, or excessive fouling of the condenser tubes.

x

Leaking air inlet isolation valves. In a twin-element steam jet air ejector, poor condenser vacuum can result when the ejector performance is degraded because of leakage through a seemingly closed first-stage air inlet valve. This leakage causes a recirculation flow to occur between the two elements and so reduces the overall efficiency of the ejector. If the other, and previously open, air inlet valve is found to be leaktight when closed, ejector performance and condenser vacuum might be improved by switching elements.

3-6


3.3.2 Gradual Loss of Vacuum Some of the causes for a gradual falling off in vacuum could be attributed to the following problems: x

Ejector nozzle or diffuser eroded or corroded. It is recommended that the parts be inspected periodically and a record made of the wear found. If replacement of these parts occurs too frequently, the cause of failure must be determined. Usually, it is found to be wet steam.

x

Improper operation of condensate trap. To correct this problem, the trap should be disassembled and cleaned. Proper drainage should also be checked.

x

Clogged loop seal drain pipe. To correct this problem, clean or replace the loop seal piping.

x

Leaking ejector system cooler tube. Check for any leaks by applying a hydrostatic test on the vapor side of the inter- and after-coolers. In order to locate the tube that is leaking, it will be necessary to remove the waterbox cover and close the inter- and after-cooler drain valves. Replace or plug any damaged ejector cooler tubes.

x

Wet steam. A fluctuating steam pressure gage at the inlet to the ejector might indicate the presence of wet steam. The steam piping should be examined to ensure that there are no low points for condensate to accumulate and that the piping is properly insulated. Key Technical Point A gradual decrease in vacuum by the steam jet air ejectors could be caused by a corroded or eroded nozzle, condensate trap mis-operation, clogged loop seal drain pipe, leaking cooler tubes, and wet steam.

3.3.3 Poor Vacuum and/or High Outlet Water Temperature Typically, the cooling water supply to the ejector system is the condensate from the main turbine condenser. At low turbine loads, the condensate flow might be insufficient to sustain proper cooling within the ejector system. If no alternative source of freshwater supply is available to replace the condensate flow, a loss of vacuum can result, along with high discharge temperatures on the outlet of the ejector condensers. 3.3.4 Faulty Operation of the Steam Jet Air Ejectors There are at least seven possible causes of faulty operation of a steam jet air ejector. It will be necessary to check for any one or more combinations of these conditions if trouble is experienced with the ejectors. x

Insufficient cooling water. An insufficient supply of cooling water can be determined by observing the temperature of the water entering and leaving the air ejector. If the temperature rise in the ejector inter-cooler does not exceed the design condition, then the cooling water supply is adequate.

3-7


x

Steam nozzles plugged with scale. A scale deposit might form in the throats of the steam nozzles, consisting of chemicals used in the treatment of the feedwater. When this occurs, the scale should be removed with drills of the same diameter as the nozzles.

x

Water flooding the inter-cooler of the condensing ejector design. Flooding of the intercooler with water can be caused by faulty drainage. This can usually be established by observing the temperature of the intercooler shell.

x

Low steam pressure. Low steam pressure might be due to clogging of the steam strainers or orifice plates with pipe scale or sediment, improper operation of the regulating valve, or the pressure of the steam supply to the pressure regulators being too low.

x

High backpressure at ejector discharge. High backpressure at the discharge of the ejector sometimes occurs when it discharges into a common exhaust system together with other equipment. If this happens, it will be necessary to provide an independent discharge from the ejector to the atmosphere.

x

Loss of the water seal in inter-cooler drain loop. Loss of water in the drain loop takes place occasionally in installations where the vacuum in the system is subject to sudden fluctuations. A sight glass is recommended on the inter-cooler drain loop to show whether the loop is properly sealed when the ejector is in service. This sight glass should be as near the bottom of the drain loop as possible. If the water is visible anywhere in the glass, the loop is properly sealed. However, if no water is visible or if it surges violently, the indications are that the drain loop has become unsealed. When this happens, some of the air removed from the main condenser by the primary element is recirculated and flows back through the drain loop to the main condenser, thereby reducing the vacuum. To re-establish the seal in the drain loop, it is necessary only to close the valve in the drain loop line provided for this purpose. This valve usually is located close to the condenser. This valve must be closed for the short period of time required to form sufficient condensate and refill the loop. After the water again shows at the top of the gage glass, the valve should be opened very gradually. If the valve is opened too quickly, the difference in pressure will cause the water to surge and again unseal the loop. In certain cases, some drain loops have a tendency to be unstable because of fluctuations in condenser vacuum. In such instances, some plants have operated with the valve in the drain loop line partly throttled. The opening should be enough to pass the condensate at all times.

x

3-8

Leakage through a closed air inlet valve in a dual-element ejector. Such a leakage establishes a recirculation flow between elements that reduces the overall efficiency of the ejector. Steam jet air ejector performance and condenser vacuum might be improved by switching elements, if the previously open air inlet valve is found to be leaktight when closed.


3.3.5 Ejector Field Testing It is difficult to check the operation of an ejector in the field, but some testing can be accomplished by checking the shut-off performance of each ejector. It is recommended that tests be performed when the unit is first placed in operation and that these readings are kept on file for future reference. If an ejector is operating satisfactorily but suddenly loses vacuum and then re-establishes its performance immediately, the probable causes are among the following: x

Momentary drop in steam pressure

x

Slugs of water in the motive steam

x

Momentary increase in backpressure

x

Momentary increase in air leakage

x

Temporary increase in condensing water temperature

x

Temporary decrease in condensing water flow

If an ejector operates satisfactorily over an extended period and then gradually loses vacuum, it might be an indication of internal wear. Ejectors should be inspected periodically and components replaced as needed. 3.3.6 Problems with Liquid Ring Vacuum Pumps (LRVPs) The principal elements for trouble-shooting potential problems with LRVPs are shown in Figure 3-4.

3-9


Figure 3-4 Trouble-shooting Problems with LRVPs [3]

The first response to a poor condenser vacuum is to check whether a sufficient number of pumps are in operation. The air in-leakage is then checked and steps taken to reduce the leakage if needed. If modern instrumentation is available, air in-leakage and pump capacity in terms of either ACFM (actual cubic feet per minute at operating conditions) (cubic meters per hour) or mass flow rate can be checked. If the capacity is low, the pump will need attention. This includes adjusting the operating conditions or performing maintenance. Assuming the above conditions have been met, the separator level should then be examined and, if low, makeup water should be added. Air leakage at the LRVP shaft packing gland should be checked. If a leak is suspected, a hose with a small stream of water can be sprayed on the rotating shaft to temporarily stop the leak. A measurement of the disappearance of the leak can be made using the LRVP exit rotameter or by measuring the mass flow rate or ACFM (cubic meters per hour) capacity on the suction side of one LRVP, as mentioned above. If problems persist and the pump vacuum is higher than the vacuum in the condenser, there might be a restriction or a closed valve between the condenser and the pump. Similarly, if the seal water flow is low, there is probably a restriction within the seal water piping.

3-10


Finally, if the seal water temperature is high, it probably indicates a problem with the heat exchanger. Fouling would be suspected to cause a problem with the heat exchanger. 3.3.7 LRVP Checklist of Operating Variables The Performance Standard for Liquid Ring Vacuum Pumps, Ninth Edition by the Heat Exchange Institute lists the following checklist of operating variables: x

Non-condensable flow rate through the pump. Non-condensable gases will decrease the pressure of the pump.

x

Inlet seal water temperature. A cooler seal water temperature will increase net capacity as well as lower the effective vapor pressure of the seal water, allowing the pump to achieve a higher vacuum.

x

Seal water flow. Reduced seal water flow will result in an increase in temperature rise and a reduction in pump capacity, possibly resulting in increased condenser pressure.

x

The inlet mixture temperature (that is, vapor subcooling)

x

Pressure drop between pump inlet and condenser. Excessive pressure drop can be the result of restrictions between the vacuum pump and the condenser, causing the vacuum pump to operate at a higher vacuum than necessary.

x

High backpressure at pump discharge. High backpressure at the discharge of the pump sometimes occurs when it discharges into a common exhaust system together with other equipment. If this happens, it will be necessary to provide an independent discharge from the pump to the atmosphere.

3-11


4 PERFORMANCE

Key O&M Cost Point Condenser performance significantly affects the heat rate and generation capacity of a power plant. A 1 in. Hg (2.5 cm Hg) increase in turbine backpressure can result in a 2% increase in heat rate. Due to changing plant conditions of cooling water flow rates and water inlet temperatures, the condenser backpressure is not a true indication of its efficiency. Condenser performance evaluation requires extensive data collection and analysis. Deviation from the design performance curve over time will help identify any degradation. To obtain reasonable data, trends must be adjusted for deficiencies such as surface area lost due to tube plugging. Section 4.7 includes information on condenser performance calculations and monitoring. Condenser fouling has a profound effect on condenser performance and is caused by several mechanisms. Section 5 addresses the causes of biofouling in the condenser.

4.1

Heat Transfer [4]

The basic heat transfer formula for condenser performance is developed as follows: Q = (K/L) A (th - tc )

(eq. 4-1)

where, Q = Heat transfer rate, Btu/hr (J/sec) K = Thermal conductivity, Btu/hr ft/qF (Watt/m qK) L = Thickness of material, Ft (m) A = Cross-sectional area, Ft2 (m2) th = Hot surface temperature, qF (qC) tc = Cold surface temperature, qF (qC) This basic equation assumes the heat transfer surface to be uniformly flat. In condenser tubes, the heat transfer surface is circular with the inner surface smaller than the outer surface. When 4-1

EPRI Licensed Material Performance

calculating the surface area of a tube, an effective diameter has to be used. When determining the thermal conductivity of the material, it is necessary to consider the tube material, any coating that has been applied, and any film that forms during normal operation. In determining thermal conductivity, it is important to include any film that forms during normal operation. Once this information has been considered, then the effective thermal conductivity of the composite surface can be calculated using the following formula:

1 Ke

1 1 1 etc. K1 K 2 K3

(eq. 4-2)

where, Ke

= Effective Thermal Conductivity of the composite surface Btu/hr ft/qF (Watt/m qK)

K1, K2, K3, etc. = the thermal conductivities of each independent layer One difficulty in accurately determining the thermal conductivity of a tube wall surface is the fact that the fluid flows mostly through the center of the tube. A thin static layer of the fluid (known as film) adheres to the tube wall surface in contact with the fluid. These static layers on the inside and outside of the tube need to be taken into account in calculating the effective thermal coefficient of the composite surface. Film coefficients are dependent on the fluid temperature, density, viscosity, specific heat, flow velocity, and shape of the heat transfer surface. 4.1.1 Condensate Subcooling [3] Heat transfer theory indicates that the mean temperature of the condensate at the tube surface and, subsequently, the temperature of the cooling water, must be less than the temperature of the condensing water vapor. This is necessary for heat to flow from the condensing vapor through the tube walls and into the cooling water. As the vapor progresses through the bundle, the heat transfer coefficient of the rows in the tube bundle tends to fall from row to row. This tends to further reduce the mean temperature of the condensate on each tube. There is an inherent tendency for the temperature of the condensate, and in particular on the tube ends nearest the inlet waterbox, to be below that of the exhaust vapor temperature. When the temperature of the cooler condensate regions is below the exhaust vapor temperature then these condensate regions are considered subcooled. In these regions, there is a marked increase in oxygen solubility. To minimize the effects of condensate subcooling on certain sections of tubes, condenser designers introduce lanes into the tubesheet layout. In this way, some of the incoming vapor can enter the tube bundles at lower rows and so regenerate the temperature of the condensate as it cascades down the tube bundles. The ultimate degree of condensate subcooling that is experienced varies with load and cooling water inlet temperature. At full load, the condensate temperature is normally slightly less than, but approaches that, of the incoming exhaust vapor. If there is little or no suction head pressure 4-2


at the suction of condensate pumps (for example, due to a shallow hotwell depth), then the slightly lower temperature also helps to reduce pump cavitation. This is because the condensate at saturation temperature is more likely to flash into steam. Condensate accumulates in the hotwell below the condenser tubes. Normally, the water level in the hotwell is maintained below the condenser tubes. Either by intention or by malfunction of level control, the hotwell level can rise and flood the lower tubes. This causes the condensate to subcool below the saturation temperature corresponding to the condenser pressure. It can cause increased levels of dissolved oxygen and corrosion of the bottom condenser tubes. It also results in increased heat rate because the condensate requires additional heating. Key O&M Cost Point As a rule of thumb, each 5 degrees of condensate subcooling results in a 0.05% increase in heat rate. Some plants prefer to operate with condensate subcooling because it reduces cavitation in the condensate pumps. The need for this practice is questionable because many condensate pumps are located well below the hotwell to minimize cavitation or are designed to operate in a cavitation mode. 4.1.2 Hotwell Subcooling [3] To understand hotwell subcooling, consideration should be given to performance of the turbine and plant design. It is a design objective that the condenser should remove the latent heat of vaporization from the steam. However, the condenser should not remove any more heat than that. At full load, it is desirable that the steam leaving the final stages of the low-pressure turbine contain a small amount of condensed water in the form of a mist. To maintain these two states of water and vapor, the operational conditions of the condenser circulating water flow rate and temperature are considered. Variations in the nominal range of circulating water temperature or flow rates will cause the turbine exhaust steam quality to change. As an example, if only the circulating water temperature decreases then the average hotwell temperature will decrease. This causes a reduction in turbine backpressure. This decreases the moisture concentration at the final turbine blade stage. When there is no longer any water in these final stage turbine blades, the steam exiting the turbine experiences choked flow that limits the flow of steam. More thermal energy removal by the condenser, either by lower circulating water temperature or higher flow rate, results only in subcooling of the hotwell condensate. This allows the hotwell temperature to fall below the temperature of the turbine exhaust steam. Because of the dry state of the turbine exhaust, the steam can be considered superheated. This hotwell subcooling is uneconomical because the excessive amount of heat removed by the subcooling needs to be restored in the steam generator or by adding more fuel to the boiler. In addition, subcooling significantly increases oxygen solubility.

4-3


4.2

Condensing Duty [1]

The condensing duty is the total heat transferred to the condenser circulating water. The condenser duty can be calculated by subtracting the steam cycle side non-condenser heat flows from the energy delivered to the steam cycle, Qt. Typically, the non-condenser heat flows are generator electrical output, generator losses, auxiliary steam, and steam-driven feedwater pumps. Steam generator blowdown from PWR plants should also be considered. The accuracy of this calculation depends very much on the accuracy of the instrumentation used to measure the parameters involved. Q=Qt-Qelect-Qgen-Qaux-Qfwp-Qbd

(eq. 4-3)

where, Qt

= heat load to steam cycle

Qelect = generator gross output Qgen = generator losses Qaux = auxiliary steam loads Qfwp = steam turbine driven pump load Qbd = steam generator blowdown load All heat loads need to be converted to a common set of dimensions. Condensing duty can be calculated based on circulating water flow and temperature flow: Q = W Cp (Tout – Tin) where, Q = Condensing duty, Btu/hr (j/s) W = Circulating water flow rate, lbm/hr (kg/sec) Cp = Circulating water specific heat = 1.0 Btu/lbm-qF (j/kg-qK) Tin = Cooling water inlet temperature in ºF (qC) Tout = Cooling water outlet temperature in ºF (qC)

4-4

(eq. 4-4)


Condensing duty can also be calculated using turbine exhaust flow and enthalpy into the condenser Q = Wex (hex – hc)

(eq. 4-5)

where, Wex = Turbine exhaust steam flow, lb/hr (kg/sec) Hex = Turbine exhaust steam enthalpy, Btu/lb (j/kg) Hc = Condensate enthalpy (enthalpy of water at the condensing pressure), Btu/lb (j/kg) Turbine exhaust flow and enthalpy are not measured. Instead, this method requires that these parameters be estimated using turbine electrical output and the turbine heat balance or thermal kit. This method is inherently inaccurate.

4.3

Heat Transfer Coefficient [3] Key Human Performance Point There are two principal ways of estimating a condenser’s current performance, the Heat Exchange Institute (HEI) method [6] and the ASME method [7]. Both compare the current value of the effective heat transfer coefficient (Ueff), computed from present steam and water temperatures and cooling water flow rate, with a reference value calculated according to one of the two procedures.

By rearranging the well-known Fourier equation for heat transfer, the effective heat transfer coefficient, Ueff, of the condenser can be calculated from: Ueff

Q A*LMTD

(eq. 4-6)

where, Q = Heat Rejection Rate, Btu/hr (j/s) A = Tube Surface Area, sq. ft. (sq. meter) Tout Tin § Tv Tout · ln ¨ ¸ © Tv Tin ¹

LMTD

Tv

=

Log mean temperature difference in ºF (ºC)

(eq. 4-7)

Vapor temperature in shell in ºF (ºC) 4-5


Tin

=

Cooling water inlet temperature in ºF (ºC)

Tout

=

Cooling water outlet temperature in ºF (ºC)

To calculate an accurate value of Ueff requires knowledge of the cooling water flow rate, representative values of the inlet and outlet water temperatures, and the compartment backpressure. For multi-compartment condensers, this set of information is required for each compartment. Deviations in the condition of the condenser from design because of fouling or air in-leakage will cause the value of Ueff to differ from its design value at the same load. Given the mechanical design details of a condenser, there is an equilibrium backpressure that corresponds to the set of operating conditions consisting of condenser duty, cooling water flow rate, and inlet water temperature. For a given duty, if the cooling water flow rate falls or the water inlet temperature rises, the backpressure will also rise. A similar increase in backpressure will occur if the tubes become fouled or the concentration of non-condensables in the shell space increases. Both conditions tend to decrease the effective tube heat transfer coefficient. The concentration of non-condensables can rise if the air-removal equipment becomes degraded or if air in-leakage increases to values above the removal capacity.

4.4

HEI Method [3]

The reference value calculated using the HEI method is the overall tube bundle heat transfer coefficient and is a function of tube water velocity, inlet water temperature, tube material, tube gauge, and the cleanliness factor. Tables and curves in the HEI Standards for Steam Surface Condensers [6] allow the appropriate values to be selected, either according to the design data set or the operating data set. Let: UHEI U1 Uref FW FM FC

= = = = = =

HEI corrected heat transfer coefficient HEI uncorrected heat transfer coefficient HEI reference heat transfer coefficient Correction factor for water inlet temperature Correction factor for tube material and gauge Correction factor for cleanliness

Then UHEI = U1 x FW x FM x FC

(eq. 4- 8)

Uref = U1 x FW x FM

(eq. 4-9)

And

Design values of cleanliness factor FC are usually around 85%, but values as high as 95% have sometimes been used. 4-6


When using the HEI performance criterion, the effective cleanliness factor FCeff can be defined as: FCeff =

Ueff Uref

(eq. 4-10)

To evaluate the current state of the condenser, the value of FCeff calculated from Equation 4-10 has to be compared with the design cleanliness factor (F C) stated in the original condenser design datasheet provided by the manufacturer. However, experience has shown that the data contained in these design data sheets are not necessarily consistent. The stated value of the design cleanliness factor should be verified from the complete set of design data. These cleanliness factor calculations are most reliable when the condenser is operating close to its design or full load conditions. There is evidence that the design cleanliness factor varies with load. To evaluate performance under partial load conditions, the relationship between the design cleanliness factor and load should be established. A method for doing this is contained in “Monitoring Condenser Cleanliness Factor in Cycling Plants” by Richard E. Putman and Dale C. Karg [8]. With multi-compartment condensers, each compartment can be assigned a different design cleanliness factor; this should be taken into consideration when evaluating the performance of each compartment.

4.5

ASME Method [3]

The ASME method of calculating condenser performance uses an estimate of the single-tube heat transfer coefficient as the reference value. The value for a clean condenser is calculated from: UASME =

1 Rw + Rt + hf −1

(eq. 4-11)

The thermal resistance of the tube wall (Rw) is calculated using the Kern [9] relationship: Rw =

do  do  ln   24km  di 

(eq. 4-12)

where, di = Inside diameter of tube in inches (cm) do = Outside diameter of tube in inches (cm) km = Thermal conductivity of metal in Btu/(hr ft ºF) (watt/m ºK)

4-7


The value of the water side film thermal resistance (Rt) is calculated using the Rabas-Cane correlation:

ª º ª di 0.165 ºª do º P 0.373 R 0.0450357 « 0.835 0.538 0.462 » « 0.835 »« » ¬ U k Cp ¼ ¬V ¼¬ di ¼ t

(eq. 4-13)

where,

P = Viscosity of water at bulk temperature in lb/hr ft (kg/sec m) U = Liquid density in lb/cu.ft. (kg/cu. m) Cp = Specific heat of water at bulk temperature in Btu/lb ºF (j/s ºK) K = Thermal conductivity of water film in Btu/(hr ft ºF) (watt/m ºK) V = Water velocity in feet per second (m/s) The Nusselt factor (hf) is calculated from the properties of water at the saturation temperature that corresponds to the compartment backpressure and is calculated from:

ª k U 2g O º h 0.725« » ¬ P D ('T) ¼ 3

0.25

f

f

f

(eq. 4-14)

o

where, Do = Outside diameter of tube in feet (m) g = Acceleration due to gravity = 417E+06 (ft.lb. mass)/(hr2.lb force) (m kg)/(hr2 kg) kf = Thermal conductivity of condenser film in Btu/(hr ft ºF) (watt/m ºK)

O = Latent heat of condensation in Btu/lb (j/s) Pf = Viscosity of condensate film in ºF (ºC) 'T = Difference in the inlet and outlet cooling water temperature in ºF (ºC) With the ASME method, the term performance factor has been used instead of cleanliness factor and is calculated from: PFeff 4-8

100

Ueff UASME

(eq. 4-15)


Key Human Performance Point The ASME reference value of the heat transfer coefficient is a single-tube value and the HEI reference value is an overall tube bundle heat transfer coefficient. The value of the effective cleanliness factor (HEI method) is greater than the corresponding performance factor (ASME method) on the same condenser. It has also been observed that the design value of the ASME performance factor and the HEI cleanliness factor varies with load.

4.6

Turbine Blade Effects [1]

The change in heat rate with a change in condenser pressure is shown in Figure 4-1 for a design condenser pressure of 1.5-inch HgA (3.8 cm Hg) and a turbine inlet pressure of 1,000 psia (6.9 megapascal). Figure 4-1 shows that the last stage turbine bucket (LSB) loading has a significant effect on change in heat rate due to changes in condenser pressure. If the bucket loading, defined as design generator output in kW/sq.ft is high, then the bucket losses are high. High bucket losses decrease with increasing turbine backpressure and offset the loss in thermodynamic efficiency that occurs with increasing turbine backpressure. Most nuclear turbines have high last stage bucket loadings because turbine configurations are limited to three or fewer low-pressure turbines.

Figure 4-1 Heat Rate Effect with Changing Condenser Pressure [1]

4-9


4.7

Performance Monitoring [1,10] Key Technical Point The following parameters should be measured when monitoring condenser performance: inlet and outlet tube side pressure, inlet and outlet cooling water temperature, impressed cathodic protection settings, condenser cleanliness factor, sample fluids for contamination, turbine backpressure, and air in-leakage levels.

Performance monitoring addresses the overall integral performance of the condenser. Performance deterioration detectable by this task is likely to be caused by microbiologically induced corrosion, fouling of the tubes, scaling, deposit build-ups, and so on. Main condensers are considered to operate continuously in severe conditions. Performance monitoring every week is recommended to address the vulnerability to sudden onset and propagation of corrosion and fouling. In almost all cases, degraded condenser performance is manifested by high condensing pressure. These parameters are sufficient to determine if degraded condenser performance is due to an internal condition such as fouling or air accumulation that reduces the capability to transfer heat. The cause might be due to external influences such as high cooling water inlet temperature or low cooling water flow. In either case, the outlet temperature increases, raising cooling temperature and condenser pressure. Some plants do not have direct measurement of condenser cooling water flow using flow meters. Indirect indicators of flow are pump discharge pressure, pump motor currents, condenser inlet pressure, and cooling water temperature rise across the condenser. Pressure and temperature both tend to increase with a decrease in cooling water flow. If condensing pressure is increasing at a rate that is not consistent with the change in cooling water inlet temperature or flow, then the problem is most likely an increase in tube fouling or a buildup of non-condensable gases. Determining whether tube fouling or non-condensable gas buildup causes the pressure increase requires additional diagnostics. If cooling water flow decreases and there has been no change in circulating water system configuration, such as reduction in the number of circulating water pumps, then tubesheet fouling or tube plugging by debris is likely. The latter can be a significant problem when there is debris in the cooling water intake. Tube fouling requires periodic mechanical or chemical cleaning of the inside of the condenser tubes. Tubesheet fouling requires periodic backwashing or mechanical removal of the foulant. Tube fouling can be reduced by the use of an on-line cleaning system and an effective chemistry control program. See Section 6, Cleaning, for more details. Another condenser parameter that is often monitored is hotwell temperature. Ideally, the temperature should be near the saturation temperature of water at condenser pressure. The hotwell temperature might be a few degrees above saturation as the result of a design that ducts 4-10


the feedwater pump turbine exhaust below a perforated plate in the hotwell. If the hotwell temperature is significantly lower, there can be a heat rate penalty due to additional heat loss to the condenser cooling water. High hotwell level, resulting in flooding of some condenser tubes, can be a cause of condensate subcooling. Trending of essential variables with time can be an important aspect of plant performance monitoring. It is a way to anticipate adverse conditions and to plan corrective action in advance of conditions that result in substantial loss of generator output. Trending can be accomplished in several ways: x

Trend using a PC-based program with graphics capability and the capability to compute trend lines. Data must be entered manually unless the PC is connected into a plant data network and the network contains the data points needed for trending. Manual data entry might consist of data entry to a hand-held data collection device that can be downloaded to a PC program.

x

Trend using the plant process computer if the computer receives and stores the appropriate data points. Algorithms to compute trends are available as standard packages or can be developed from mathematics and statistics textbooks.

4.8

Performance Software Tools

Two EPRI products that assist in performance evaluations for the condenser are described below: 1. EPRI has developed the Nuclear Thermal Performance Advisor (NTPA), a PC program based on expert system technology and the Thermal Performance Diagnostic Manual, NP4990-V1-3, April 1987. The NTPA is an interactive, heat rate diagnostic expert system that provides performance engineers with assistance in identifying causes of lost power generation. One diagnostic area is the condenser. 2. EPRI has a software solution product, The Heat Exchanger Workstation-Condenser Application (HEW-CA) initiated in April 1996 [11]. The software includes the following five tightly integrated applications: x

Diagrammer – to specify the schematic and design of the condenser

x

Performance Analyzer – to compute condenser performance parameters based on operating conditions

x

Performance Advisor – to provide a cause analysis in the event of condenser deficient performance and to suggest corrective actions

x

Tube Failure Advisor – to provide failure mechanism analysis based on operating/design conditions

x

Operations and Maintenance Manual – to provide an electronic, fully indexed reference system

4-11


This software package is available from the EPRI Nuclear Maintenance Application Center (NMAC) and the Fossil Maintenance Application Center (FMAC).

4.9

Instrumentation [12]

This section discusses the instrumentation needed to measure and monitor condenser performance. Figures 4-2 and 4-3 show the steam and water side condenser instrumentation.

Figure 4-2 Typical Steam Side Instrumentation [13]

4-12


Figure 4-3 Typical Water Side Instrumentation [13]

The following are parameters that need to be measured and a suggested form of instrumentation to accomplish each task. 4.9.1 Condenser Pressure Turbine backpressure is typically measured by a series of basket-tip pressure-sensing devices located in the exhaust hood. Measurement at this point does not accurately indicate condenser pressure, as defined by the HEI standards [1] as the absolute static pressure that is not greater than 1 ft (30.5 cm) above the condenser tube bundles. Typically, condenser pressure is measured by a tube penetration or a skin tap in an area where steam flow is uniform and perpendicular. However, the pressure is measured more accurately by a series of parallel-plate measurement devices located 1ft (30.5 cm) above the tube bundle and distributed to obtain an accurate average pressure. According to the ASME Power Test Code on Steam Condensing Apparatus (PTC 12.2, 1975), approximately one measurement point for every 100 square feet (9.2 square meters) of cross-sectional tube bundle area is required in the plane of measurement, with a minimum of four measurement points. Basket tips should be installed at a 45q angle from the vertical. Guide plates should be installed so that steam flow is perpendicular to the pressure tap, avoiding locations where there are high local steam velocities. The basket tips should be installed in each condenser compartment. Four basket tips for each compartment is suggested. Basket tip sensing lines should be sloped to avoid moisture accumulation. The sensing line should be purged before each reading.

4-13


4.9.2 Air In-Leakage Equipment typically used to measure airflow includes rotameters, pitot tubes, flow meters, and multisensor probes. The multisensor probe (MSP) is a standard instrument for measuring the amount of air inleakage. A sensor is installed in each air-removal line leaving the condenser. This instrument has been used with the tracer gas for locating air in-leakage. More information on this probe can be found in Section 7.2.2 of this guide. Monitoring might consist of the placement of a rotameter at the discharge side of the vacuum pump/air ejector. Monitoring of airflow downstream of the air receiver is preferred because the air/steam mixture typically evacuated from the condenser has been separated. The air receiver separates the steam/air mixture so that mostly air flows through the rotameter. If a separating device is not present in the installed air-removal system, it is possible to calibrate the rotameter for an air/steam mixture. Figure 4-4 is a picture of a rotameter.

Figure 4-4 Rotameter Type Flow Meter [3]

An alternative method of air in-leakage measurement uses pitot tubes. A pitot tube can measure the total airflow if adequate velocity head is available. Accurate pitot tube measurement depends on locating the pitot tube in a straight run of pipe of sufficient length to avoid pressure fluctuations. It is often difficult to find suitable locations for accurate pitot tube measurement.

4-14


Vane-type flow meters can be useful to establish base curves at various loads and condenser pressure levels. Any increase above the base curves can be used as an indication of an air leak. These meters are not used for an absolute measurement of air in-leakage. Orifice plates with pressure transmitters and electronic mass flow meters are also used. 4.9.3 Condensate Oxygen Condensate dissolved oxygen is of critical importance in determining condenser performance and integrity. Dissolved oxygen in the condensate is usually measured at the discharge side of the condensate pump. It is preferable to measure oxygen concentration closest to the hotwell on the suction side of the condensate pump. This, however, is generally not practical because the condensate is at a negative pressure on the suction side of the condensate pump. The most common method of dissolved oxygen determination is to analyze slip stream flows or periodic grab samples. The samples are taken from sampling connections on the condensate pump discharge and sent to a sample sink usually located in the water chemistry laboratory of the plant. The samples are generally analyzed by the color comparator method to determine oxygen concentration. The major shortcoming of this method of analysis is the very slight color differences that occur between discrete oxygen concentration levels. Usually the color comparator kits are graduated in 5 ppb units. The major advantages of this method are speed and low cost. Analyzers with strip chart recorders can accurately measure dissolved oxygen concentration in the condensate system. Typically, the analyzers consist of a readout panel/transmitter and an online probe. When condensate flows through the sample probe, oxygen diffuses through a membrane and is electrically reduced at the probe cathode. At the same time, an equal amount of oxygen is generated at the probe anode. Diffusion through the permeable membrane continues until the oxygen pressure on both sides of the membrane is equal. The current necessary to maintain the pressure equilibrium is converted by electrical circuitry to read the dissolved oxygen concentration in parts per billion. The accuracy of the analyzers is typically + 2 ppb. The advantages of continuous analyzers are accuracy, ease of operation, and the ability to alarm when results are not within specifications. The primary disadvantages are installation cost, maintenance cost, and pressure/temperature limitations. If a test connection does not exist on the discharge side of the condensate pump, the pipe will have to be tapped. Additionally, it is necessary to install a pressure regulator in the sample supply line to limit the sample pressure to less than 50 psig (345 kilopascals). The maximum allowable temperature is approximately 175ºF (79ºC).

4-15


4.9.4 Hotwell and Condensate Temperature The point where the condensate temperature is taken is critical. Many units take measurement of condensate temperature at the discharge of the condensate pumps. This measurement location has inaccuracies because condensate pump power input adds heat to the condensate. The temperature is most accurately measured at the condensate pump suction after some mixing has occurred in the suction piping. Mercury in glass thermometers and calibrated resistance thermometers or thermocouples can be utilized to accurately measure condensate hotwell temperature. 4.9.5 Circulating Water Flow Flow rate measurement might be required to verify the performance of the circulating water pumps or to evaluate the condenser thermal performance. Most power plant circulating water systems have substantial flow rates. Flow meters are not typically included in the original design and retrofit installation of these devices can be either very expensive or physically impossible. There are a number of direct and indirect methods for measuring circulating water flow rate. The direct methods are best, but these are often limited by a plant’s arrangement. Applicable test code approved methods include: x

Velocity traversing

x

Dilution techniques

x

Sonic devices

Methods such as velocity traversing using pitot tubes or the dilution technique using dye as a tracer can be labor intensive. The equipment cost is low, due to the availability of rental equipment. Sonic flow testing has a high capital equipment cost because of the multiple transducer mounts required. Circulating water flow can be very difficult to measure. This is generally because of large inaccessible pipes and insufficient straight runs. Accessibility, coupled with required straight runs, limits pitot tube traverses, but dye dilution testing and sonic flow testing are often viable. The following sections present brief descriptions of various flow measurement methods, their advantages and limitations. It is important to note that the choice of one method over another requires careful evaluation to determine the case-specific cost, the test code acceptance criteria, and the likelihood of achieving satisfactory results. 4.9.5.1

Velocity Traversing

Alternate methods of direct measurement can employ an annubar, pitot tube, or velometer. These methods require long lengths of straight and constant geometry conduit. Accurate measurement of a conduit cross-section at the measurement location is required.

4-16


An annubar is essentially a fixed multiple port pitot tube. Annubar applications are more common for smaller pipe diameters. The annubar application is a proven technique and has been used in pipes of up to 12 feet (3.6 meters) in length. However, it should be carefully evaluated before use in a circulating water system application. The recommended approach would be in situ calibration of the annubar by means of another high accuracy flow measurement technique such as dye dilution or pitot tube traverse. When a pitot tube or velometer is used, a series of point velocity measurements are integrated over the flow measurement cross-section. A pitot tube can be used where velocities are between 4 to 15 feet per second (1.2 – 4.6 meters/sec). For lower velocities in large conduit sections, a velometer is the preferred device. Both devices require long lengths of straight conduit runs to minimize variations in flow direction and to establish a predictable boundary layer. For circular pipes, the diameter is traversed at two perpendicular locations with multiple measurement points on each traverse. Circulating water piping is often buried and inaccessible. If this is not the case and there is a long straight run of pipe, pitot tube traverses will result in a highly accurate direct measurement. The traverses show the velocity profile across the pipe and, from this, the average flow can be determined. High accuracy can be achieved if the velocity profile is relatively flat. The disadvantage of pitot tubes is that they measure the flow velocity at only one position at a time. Full traversing is required to derive the total flow rate. A pitot tube traverse is a Code-accepted method of measuring large flow rates typical of circulating water systems. Aerodynamically shaped pitot tubes can be used to counteract the turbulence levels in large diameter pipes, whereas, cylindrical ones can be suitable for short length insertions into the pipe. The accuracy of the pitot tube method is within approximately 2.5%. An alternative to using pitot tubes is to traverse the pipe with a propeller-type velocity meter. These traverses are usually very accurate and feasible for large circulating water pipes having relatively low velocity. For pipes more than 10 feet (3 meters) in diameter with velocities in excess of 9 feet per second (2.7 meters/sec), the measurement is complicated by the tendency of the velometer to vibrate. Velometers require laboratory calibration for acceptable accuracy. A typical test using this device would cost about the same as that for the pitot tube. 4.9.5.2

Dye Dilution Testing

Another method to determine flow rate involves dye dilution testing. Fluorescent dye is injected upstream in the circulating water system at a known rate. Dye concentration is determined at a point downstream with a fluorometer after adequate mixing has taken place. By factoring in the background fluorescence before injection, and the dye injection rate, the circulating water flow rate can be calculated quite accurately (within 2.0%) using a mass balance approach. The main disadvantages are that the method is labor intensive and requires complete mixing of the injected dye solution before it reaches the sampling point. The disadvantages are that the circulating water pipe section geometry is not a limitation and the method is low cost.

4-17


A dye dilution test could be performed every two to three years to calibrate the pump curves. The dye dilution method can also be used to calibrate other permanently installed flow measuring devices. This method is becoming the most often chosen method due to the favorable combination of high accuracy and low cost. In addition, a unit shutdown is not required. It is important to use fluorescent dyes that are environmentally safe. 4.9.5.3

Sonic Flow Devices

Sonic flow devices have also been used successfully to measure circulating water flow rates. Multiple pairs of ultrasonic transducers are mounted on opposite sides of a pipe so that the plane in which the transducers lie is at a 45-degree angle to the pipe axis. The acoustic propagation times, both upstream and downstream, between each pair of transducers, are measured and an electronic digital signal conversion results. By using several chordal paths, the ultrasonic flow meter is capable of achieving accuracies within 1%, even with poor velocity profiles. However, the use of sonic flow devices can be expensive on large-diameter pipes. 4.9.6 Pump Curves and Total Dynamic Head Pump total dynamic head is the measure of energy increase imparted to the flow by the pump. It is the algebraic sum of the static discharge head, the velocity head at the measurement connection, and the vertical distance from the connection to the water level in the pump bay, minus any head loss to the pump section. Liquid columns (piezometers, U-tube manometers, or calibrated pressure gauges) can be installed on the pump discharge header to directly measure the pump static discharge head. Water level in the pump bay can be directly measured with a surveyed staff gage or an electric drop line with measuring tape referenced to a temporary benchmark. The elevation difference between a piezometer water column and the water level in the pump bay is added to the velocity head. This is derived from the flow measurement test and the circulating water pipe size to calculate pump total dynamic head. Once the pump head capacity curve is verified, it can be indirectly estimated what the circulating water flow rate is by entering the pump curve with the total head to read the flow rate. The pump curve accuracy can be verified by one of the more accurate methods of flow testing such as a dye dilution test. This should be repeated every two or three years due to pump wear. 4.9.7 Flow Monitor Technique The flow monitor technique uses pressure drop in the condenser outlet waterbox to determine circulating water flow by graphical method. The objective is to develop a relative condenser flow rate monitor using a differential pressure technique developed by Tennessee Valley Authority (TVA). This technique takes advantage of the fact that flow acceleration and flow separation cause a differential pressure to exist between the outlet waterbox and the outlet tailpipe. Because the Reynolds number of the flow is very high, the flow rate is proportional to the square root of

4-18


the differential pressure. This technique is reportedly insensitive to fouling of taps because both sets of taps are in regions of low velocity. The experience of TVA has shown that a pressure differential of up to 2 feet (61 cm) can be expected. Because of the complex waterbox/tailpipes configuration and flow patterns, the constant of proportionality cannot be determined theoretically. It requires an in situ calibration by tracer dye method or other high accuracy flow measurement technique. This flow monitor would provide the plant with a permanently installed condenser flow measuring device located directly within the turbine building. Together with other condenser measurements, the plant would have all the parameters needed for a condenser performance monitoring program. 4.9.8 Circulating Water Temperature Typically in power plants, inlet and outlet water temperatures are continuously monitored by means of resistance temperature detectors (RTDs) located in the pipes entering and exiting the condenser waterboxes. There might be three or four RTDs per pipe, mounted on the pipe wall and usually extending 8 to 10 inches (20.3 – 25.4 cm) into the flow stream. Inlet water temperature measurement is accurate with this instrumentation because the temperature is usually consistent over the entire cross-section of the pipe. However, at the outlet end of a condenser, concentric thermal stratification might occur several pipe diameters downstream of the waterbox. Different bundle designs might cause different stratification geometry. If the RTDs are not located far enough downstream of the waterbox discharge for thorough mixing of the outlet water (that is, at least 10 pipe diameters downstream), they might indicate a higher temperature close to the pipe wall, thus overstating the mean temperature. For example, an RTD extending 10 inches (25.4 cm) from the wall of the condenser tailpipe could provide an indication of outlet temperature that can be significantly higher than the mean temperature. Pipe traversing using an RTD or thermocouple test probe can be performed to determine the extent of stratification and, thus, the accuracy of measurement. The traverse data can be used to correct the temperature indicated by the instruments. Other measurement methods can also be employed such as thermocouples mounted on existing grids traversing the outlet pipe. Another alternative is to provide temperature measuring sensors at different points in the crosssection of the pipe. Another method employs a crosscut temperature measuring device that includes a hollow tube filled with homogeneous oil and a wire located longitudinally through the tube center. By measuring the average temperature of the wire as the hollow tube is traversed through the circulating water pipe, the average temperature of the condenser discharge is obtained. Generally, the thermowells are located in the discharge of the condenser due to stratification concerns. The crossover pipes are approximately 10 feet (3 meters) in length. The thermowells are located in the crossover pipes, between the high- and low-pressure zones of the condenser. The thermowell material should be consistent with the plant water chemistry. Easy location access is required to monitor the temperature measurement indications of the thermowells.

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4.9.9 Pressure Drop Condenser pressure drop on the circulating water side is typically measured by means of pressure taps on the inlet and outlet waterboxes. These pressure taps can be connected in individual or differential pressure measuring devices (differential pressure transmitters or mercury manometers). The tap point should be located in a low-velocity zone. If the pressure taps are static-type taps located near the tubesheets, the measured pressure difference equals the pressure loss through the tubes. The tube velocity can then be determined by a graphical method. The accuracy is affected by tube fouling. Because the differential method is not an absolute method, a calibration relating differential pressure and circulating water flow rate is required. Using techniques such as the heat rejection rate method or the dye dilution method is acceptable. 4.9.10 Waterbox Levels In once-through siphonic circulating water systems, a portion of the dissolved oxygen in the circulating water is released during its path through the condenser. The condenser is normally the high point in the system and, together with the temperature rise across the condenser, the saturation point of the oxygen dissolved in the circulating water is reduced. This release of oxygen is not as severe in closed loop systems because the system operating pressure is often above atmospheric pressure. In both cases, venting of the condenser waterboxes is desirable. If venting is inadequate, there will be a loss of complete submergence of the tube bundle that could affect condenser thermal performance. In addition, there could be additional flow resistance imposed on the circulating water pumps and their flow rate might be reduced. As a result, monitoring of the water levels in the waterboxes is an important surveillance point. This level is often monitored physically by observing the level in a gage glass or porthole installed near the top of each waterbox. The need to periodically observe these levels is often neglected by operating personnel. This neglect is, in some cases, unavoidable because the designers frequently place the sight glasses in hard-to-reach locations. In other cases, the levels cannot be monitored because the sight glasses are not kept clean. Alternative level indication instrumentation could be applied to the waterbox. However, sight glass monitoring continues to be the most cost-effective method. An alternate type of sight glass is clear plastic tubing connected to both the top and bottom of the waterbox. At minimum cost, the clear plastic tubing can be replaced when fouled.

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5 FOULING

Fouling of the condenser includes any organisms, organic or inorganic, that interfere with the circulating water in the tubes and, ultimately, with the heat transfer process. When there is an increase in condenser pressure and a decrease in cooling water flow, fouling is the most likely cause. Other indications of fouling include an increased pressure drop and a reduction in temperature change for the inlet and outlet cooling water. Fouling impacts the output of the plant as it affects the condenser backpressure. The plant availability can be affected during seasonal changes that produce annual fish runs, grass movement, seaweed deposition, accumulation of leaves, and so on. The deposits on the tube reduce heat transfer rates, decrease cooling water flow, and increase pumping costs. The formation of these deposits is a function of the cooling water environment, flow velocity, and the season. In addition, the solubility of certain compounds, such as calcium carbonate, decreases with increasing water temperature. Key Technical Point There are two main types of biofouling: macrofouling and microfouling. Macrofouling is defined as the blockage of condenser tubes by organic or inorganic debris such as sticks, leaves, fish, mussels, and so on. Microfouling is the accumulation of deposits (inorganic scales or organic growths) on the inside of the tubes. The following sections discuss macrofouling, microfouling, chemical treatment, water regulations, chemical application methods, and a fouling monitor.

5.1

Macrofouling [14]

Organic or inorganic debris can occur from traveling screen carryovers or from growth of organisms on the condenser and water conduit walls. The organisms eventually dislodge and plug the tubes. Macrofouling upstream of the circulating water pumps can reduce the available net positive suction head. This results in pump cavitation and reduced flow. Debris, lodged at the entrance to or inside the condenser tubes, can increase flow velocities around the debris. This increased velocity will erode any protective film and, subsequently, corrosion at this part will occur at a higher rate. Copper-alloy tubes are more prone to this phenomenon while stainless steel and titanium tubes are less susceptible to this attack. Organic debris left in the condenser tubes during outages decomposes biologically. This process of decomposition can be highly corrosive and produces compounds that can promote pitting or 5-1

EPRI Licensed Material Fouling

stress corrosion cracking in copper and brass alloy tubes. Pitting can also occur in copper nickel and in 300 series stainless steel under these conditions. Prevention of macrofouling depends on site-specific conditions causing macrofouling. If the source is debris such as seaweed or freshwater vegetation, then traveling screens at the circulating water intake might prevent the debris from flowing into the condenser. If the source is an organism such as clams, then a biocide is needed. Many plants have the capability to backwash the condenser to remove macrofouling. Strategies for backwashing depend on circulating water conditions and trends in condenser performance. To determine methods that control macrofouling problems, it is important to understand certain characteristics of various fouling agents. The freshwater and saltwater environments yield different organisms that can cause fouling problems. Some of these organisms are discussed in the following two sections. 5.1.1 Saltwater Organisms x

Barnacles – Barnacles are one of the most common fouling mechanisms. Numerous species occur along the coastline of the United States. As adults, they become permanently attached to a substrate and are protected by hard calcareous plates.

x

Mussels – Mussels are common fouling organisms that create severe problems at power plants. The mussel shell is three-layered and the two valves of the shell are held tightly shut by a strong muscle. This tight closure of a thick shell and firm attachment to substrate by threads make the mussel extremely difficult to move. If the adult is killed, the three- to fourinch shells might remain attached until physically removed. In some instances, mussels accumulate in such dense aggregations on intake walls and in pipes that the weight pulls large mats of mussels, shells and accumulated debris down to the floor of the structure. These dense mats can clog downstream components and the resulting debris can clog smaller pipes farther along the system.

x

Oysters – The American oyster ranges along the Atlantic and the Pacific coast. It is commonly found in brackish water near the mouths of rivers or in bays and estuaries in shallow water.

x

Bryozoans – Bryozoans are colonial animals often mistaken for other organisms such as algae, hydroids, corals, sponges, and so on. The bryozoan colony consists of numerous boxlike compartments arranged in characteristic patterns. Each compartment contains an individual animal having a tubular gut, a well-organized nervous system and other anatomical features that distinguish the bryozoans from the other groups they resemble.

x

Coelenterates – The coelenterates include relatively simple animals such as hydras, jellyfish, sea anemones, and corals. Because of the size and abundance of jellyfish, they are often responsible for damage to traveling water screen panels at power plants.

x

Tunicates – Tunicates are soft, sac-like animals growing either singly or flat, spreading forms that grow in colonies. When growing as individuals, they can grow in large, denser masses. When these masses become large and heavy enough, they can break off and clog screens, tubesheets, and other intake apparatus.

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x

Tube Worms – Tube worms are small, segmented marine worms that live in white tubules that are an inch (2.54-cm) or more in length. They can grow in such masses that they cover large areas and can be more of a fouling nuisance than the barnacle.

x

Seaweeds – Seaweeds inhabit intertidal and subtidal areas attached to the substrate by specialized features for anchoring. Seaweed can cause clogging problems by attaching to structures such as trash racks or as debris when ripped from their attachments by ocean storms.

x

Fish and Miscellaneous Invertebrates – Along the coastal United States, the herring and anchovy families, as well as various crabs and shrimp, cause occasional and sometimes severe problems. Crabs can be particularly troublesome because of their attraction to traveling screens and their ability to cling to the screen mesh. They pass through spraywashes and carry over the screens and into the circulating water systems.

x

Debris – Mussel and barnacle shells are a common blockage problem in condensers. The carryover of grasses, leaves, shell fragments, and other waterborne debris can result in severe plugging of condenser tubes.

5.1.2 Freshwater Organisms Some organisms found in freshwater are: x

Corbicula – Corbicula organisms include clams. Any water system operating within areas currently populated by this organism and utilizing raw freshwater is vulnerable to clogging by the Asiatic clam. The larvae can be carried through all standard screening equipment in power plants.

x

Algae – Various types of freshwater algae also create operational problems in circulating water systems. Being photosynthetic plants, algae species of concern at power plants only grow in areas exposed to light. The major problem caused by freshwater algae is the massive influx of mats or clumps that occur seasonally or after storms at many sites. The debris matting can become so severe that spray washes cannot remove it. Manual brushing or even burning of the debris might then be required.

x

Hydrilla – The hydrilla plant has the ability to spread rapidly and dominate natural aquatic vegetation. Water depth indirectly controls hydrilla by affecting light levels in the bottom few feet of the water column.

x

Fish and Miscellaneous Invertebrates – Many power plants experience periodic influxes of fish in large enough quantities to create operating problems. Particularly affected are traveling water screens that have been known to collapse due to rapid blockage. Condensers might be blocked if carryover or carry-through of fish occurs.

x

Debris fouling – Grasses, leaves, trees, branches, rocks, sand, and silt can cause problems in intake lines.

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5.2

Macrofouling Control Technologies [14] Key Technical Point A variety of macrofouling control technologies are used in power plants. These technologies can be categorized as: mechanical control, flow reversal, thermal backwash, hydraulic control, materials control, chlorination and alternate biofouling control methods, and manual cleaning.

The following is a discussion of these control technologies. 5.2.1 Mechanical Controls Mechanical equipment in the intake and along the pipeline has traditionally been used to protect the condenser and the circulating water system from macrofouling. A conventional power plant intake is shown in Figure 5-1.

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Figure 5-1 Power Plant Intake Schematic [14]

Effective intake screening will help minimize some of the macrofouling in the condenser. Trash racks and rakes are the first line of defense and screen out a significant portion of debris larger than 3/8 in (9.5 mm). Conventional through-flow screens can be modified to provide additional macrofouling control and reliability. Some utilities have incorporated dual-flow, center-flow and fine-mesh traveling screens at intakes to meet environmental requirements or to achieve additional condenser protection from debris carryover. These screen designs have features that can aid in macrofouling control.

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In the circulating water piping system, debris filters have been installed to supplement intake screening. These filters are commonly located upstream of the condenser inlet waterboxes. Similarly, strainers are used in service water and screenwash systems. Condenser backwash represents a last step to remove macrofouling from the tubesheet. 5.2.1.1

Trash Racks

Trash racks are the first line of defense and are used to protect the traveling screens from large debris. In some plants, racks are located at the entrance to a cooling canal; at others, the racks are located just upstream of the traveling screens. Trash racks consist of vertically aligned steel bars, spaced two to three inches (5.1 to 7.6 cm) apart, and extending from the deck to the bottom of the intake. Typically, trash racks consist of welded bar subpanels bolted to welded structural steel frames to form racks that are lowered into position in steel guideways embedded in the concrete. Racks range from 5 feet to 15 feet (1.5 to 4.5 m) in width and are usually supported by concrete piers. Trash racks can extend below concrete curtain walls that act to deflect large debris and ice, or are located downstream of the curtain wall. The racks can be set vertically or inclined up to a 1-to-5 slope. In cases where large debris (such as tires or trees) is encountered, another set of trash racks spaced 8 to 12 inches (20.3 to 30.5 cm) apart can be installed upstream of the 3-inch (7.6 cm) spaced bars to minimize the debris loading. 5.2.1.2

Trash Rakes

Conventional trash racks with light debris loading can be manually cleaned with hand rakes. The nature of this operation is such that station personnel clean racks only when the racks are considerably clogged with debris. Alternatively for light debris, some stations use cable-operated rakes as shown in Figure 5-2.

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Figure 5-2 Trash Rack and Trash Rake [14]

The rack is cleaned by a single rake that is mounted in a carriage assembly. The rake carriage is raised and lowered by two pair of cables operating from a drum hoist. The operator controls closing and opening of the rake teeth, lifting and dumping of the loaded rake, and the traversing of the entire intake. After the rake moves upward and clears the rack, the rake deposits the debris in a hopper. The trash car is mounted on a set of rails and can move to a location where the car can be lifted and dumped. For heavy debris loading such as grass, seaweed and trees, several designs have been used. One is a heavy-duty clamshell-shaped rake and another is the traveling bar rack. The traveling bar rack is similar to traveling screens with bar spacings of 0.5 to 1 inch (1.3 to 2.5 cm) between the widely spaced racks and the screens. These designs are used to screen kelp and seaweed on the Pacific coast plants. At power plants in cold-weather climates, trash racks can become clogged by floating or frazil ice in the water flow. Frazil ice is the initial crystal from which ice develops in water bodies. It is initiated by supercooling of the water caused by low air temperatures and surface winds greater than 10 mph (16 kph). Frazil crystals form on the top stratum of flow and are easily mixed into the lower strata by turbulence generated by winds and currents. These crystals can adhere to underwater trash racks, reducing or blocking water passage. Warm water re-circulation, or the introduction of steam upstream of the racks, can raise the inlet water temperature and prevent frazil ice formation. Air bubbler designs can also prevent frazil ice formation. Curtain walls upstream of the racks and below the extreme low water level are the prevalent method of floating 5-7


ice control at power plants. Floating ice booms are not very effective in preventing floating ice sheets from entering the intake system. 5.2.1.3

Traveling Water Screens

The three types of vertical traveling screens available in the United States are through-flow, dual-flow, and center-flow. The most common type used is the dual-flow. The path of water moving through the dual-flow type of traveling screens is shown in Figure 5-3.

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Figure 5-3 Typical Dual-Flow Traveling Screen Arrangement (courtesy of FMC)

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All of the vertical traveling screens discussed in this section have screening faces made of metallic or plastic mesh through which the water must pass. The mesh is mechanically rotated above water for cleaning. The screen mesh is held rigid by multiple small trays or baskets linked together to form a continuous belt. The belt revolves with the upstream side rising with its collected debris to the structure deck where the screenwash system is located. At the deck, the screenwash water system directs high-pressure sprays through the mesh to wash off debris into the disposal trenches. Most maintenance can be performed at the deck level without removing the screens from the guides. This maintenance includes basket and mesh replacement, operating chain maintenance, and motor repairs. A detailed description of the traveling water screens, debris removal systems, intake/filtering screens and strainers can be found in Condenser Macrofouling Control Technologies [14]. 5.2.1.4

Debris Filters

It might be necessary to install a debris filter before the inlet to the condenser. This is the last chance to catch debris before entering the waterbox. The capital cost for a debris filter can be high and available space can present problems for a retrofit. Filters increase circulating water system head loss and reduce circulating water flow rate. These losses can be overcome by increasing the circulating water pump horsepower. A picture of a debris filter is shown in Figure 5-4.

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Figure 5-4 Debris Filter (courtesy of Taprogge)

5.2.2 Flow Reversal Another means to supplement an effective screening system and to clean debris accumulation in the condenser waterboxes and on the tubesheets is to backwash the condenser by periodically reversing the circulating water flow direction. The condenser backwash is achieved by providing additional pipelines and valves around the condensers and by controlling the various valve positions in the circulating water lines and at the condenser. 5.2.3 Thermal Backwash Key Technical Point Thermal backwash is an antifouling technique that requires the cooling water temperature to be raised above the thermal tolerance level of the fouling organism, for example, zebra mussels. 5-11


Defouling of the intake structure and inlet water piping requires a flow reversal within the system where water is pumped through the condenser twice and then back to the intake structure. The effectiveness of thermal backwash is dependent on the appropriate choice of water temperature, exposure duration, and frequency of backwash. With the backwash is the inherently less efficient operation of the remaining condensers or heat exchangers. Total flow is reduced and/or inlet water temperature is raised above the expected normal design level. Unit output will be reduced during the backwash cycle. This procedure can be scheduled when power reduction is acceptable. 5.2.4 Hydraulic Control Key Technical Point The use of high circulating water velocity to prevent the attachment and subsequent growth of fouling mechanisms is termed hydraulic control. The velocity needed to prevent settlement of the fouling organisms is between 2 and 4 ft/sec (37 and 73 meter/min) on smooth surfaces and 4 to 6 ft/sec (73 to 110 meter/min) on rough surfaces. Several factors limit the usefulness of velocity as a macrofouling control technique: x

Critical velocities must be maintained on a continuous basis. Interruption for even a short period will result in settlement of larvae that will not be removed when the flow is resumed.

x

Critical velocities must exist very near the conduit wall (within 0.5 mm) to ensure shearing of the larvae.

x

Dead areas must be minimized. These areas include the inside of pipe bends, access chambers, expansion joints, valves, pits, and corners of culvert piping. These areas are nearly impossible to avoid.

Given these factors, hydraulic control may have little practical application alone in solving the macrofouling at power plants. However, high velocity circulating water of 4 to 6 ft/sec (73 to 110 meter/min) should be used whenever possible to inhibit macrofouling and reduce the frequency of cleaning. 5.2.5 Materials Control One approach for reducing or preventing macrofouling within the circulating water system is the use of antifouling coatings. The advantage of this approach is that marine fouling is prevented at the point of attachment, thus requiring only the intake and piping surfaces to be treated as opposed to the entire water volume. Development of copper-nickel alloy metals has provided another means of fouling control. The copper-nickel metals possess antifouling properties and are used in the manufacture of piping and components for marine service. Antifouling coatings have been developed that use organotin

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compounds as fouling control toxins. The organotin toxins are formulated into rubber sheeting and plastic pellets. Key Technical Point Copper-nickel alloys form an adherent cuprous oxide corrosion film. The copper ion content in the film, when released into the cooling water, is toxic to marine biofouling organisms and inhibits their attachment to the metal surface. Fouling organisms can attach to copper-nickel alloys’ surfaces if the water velocity is less than 4 ft/sec (1.2 m/sec). The average water velocity within a power plant circulating water system is 8 ft/sec (2.4 m/sec), while the velocities at the intake bay are about 1 foot/second (18 m/min). Special cleaning techniques are required to remove the foulants. The antifouling properties of the copper-nickel alloys are derived from the toxicity of the copper ion to marine life. Galvanic coupling of these alloys to a less noble material, such as steel, suppresses the formation of the cuprous oxide corrosion film. The result is a loss of antifouling properties and the accumulation of marine fouling as if the alloy was wood or steel. Copper oxide-based antifouling coatings can be applied to steel and concrete surfaces. They are used as part of a total coating system that consists of an anticorrosion primer over steel or a sealer over concrete, a possible intermediate coating, and a topcoat of the antifouling material. Repainting of the circulating water intakes is required every one to two years. Copper-based coatings are also subject to various mechanical failures. For example, exfoliation or loss of paint surface can be caused by dynamic action with water, impact by floating debris, or abrasive contact with entrained solids, such as sand. This contact can mechanically remove the coating and result in penetration to the substrate. 5.2.6 Chlorination and Alternate Biofouling Control Methods Chlorine, a strong oxidizing agent, is commonly used to control macrofouling in power plants. A mixture of hypochlorous acid and hydrochloric acid is formed when hypochlorite or chlorine gas is added to water. Sources of chlorine available to power plants include gaseous chlorine (stored as a liquid under pressure), calcium hypochlorite, liquid sodium hypochlorite, and onsite hypochlorite generation. Key O&M Cost Point Gaseous chlorine is frequently used by utilities because chlorine in this form is relatively low in cost. Unfortunately, chlorine gas is highly toxic. Sodium hypochlorite, although less dangerous, is more expensive than liquid chlorine. Onsite generation relieves transportation and storage problems associated with the other systems but requires auxiliary power from the plant and is capital intensive.

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There is disagreement among chlorine users as to the concentration of chlorine required to control macrofouling. Many environmental factors, such as predominant organisms, growth rates, location, season, and water temperature affect chlorine dosage and application rates. Intermittent chlorination is relatively ineffective against hard-shell foulants such as mussels and barnacles. Continuous chlorination at low levels, at least during the growing season of the macrofoulants is required to effect complete control of mussels and barnacles. See Section 5.4.4.1 for more information on chlorine applications. Besides chlorine, other oxidizing agents used for macrofouling control include ozone, bromine, bromine chloride, iodine, and chlorine dioxide. Non-oxidizing biocides include organo-metallics, chlorophenols, silver salts, and cationic substances. Because of cost, degree of effectiveness, adverse toxic side effects, lack of availability, or a combination of these reasons, these chemical biocides have not found wide acceptance. See Section 5.4.2 for more information on biocides. 5.2.7 Manual Cleaning Using divers to manually clean the wall and floor areas of the intake bays can be effective in controlling biological population growth. Typically, this is performed in conjunction with chemical treatment of the intake water to kill the organisms. Manual efforts to clean the condenser tubes and tubesheet to control macrofouling are commonly used. These efforts are labor intensive and require load reductions or the unit off-line. The tubes can be cleaned and debris and deposits removed by brushes, scrapers, or rods. Section 6 deals with the many aspects of cleaning condenser tubes.

5.3

Microfouling [15]

Microfouling is the formation of deposits on the inside of the condenser tubes and can be caused by chemical means, biological means, or both. Metal surfaces undergo chemical and biological changes when immersed in natural waters. Chemical interaction between the metal’s surface and water results in the deposition of inorganic ions and the adsorption of dissolved organic substances. This process leads to the formation of a conditioning film, approximately 1.968 micro-inches (50 nanometers) in depth. The film enables bacteria and diatoms to colonize. Those colonies produce an extracellular polymeric substance that encourages further growth of the biofilm. Interrupting biofilm growth will not necessarily solve heat transfer problems. For example, if the heat transfer surfaces continue to be covered with the dead biofilm and an extracellular polymeric substance layer, heat transfer will remain impeded. In addition, if the biofilm growth characteristics are not taken into account, then insufficient cleanup of the biofilm can lead to rapid re-growth.

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5.3.1 Biofilm Development Biofilm development consists of six steps: 1. Conditioning 2. Transport 3. Attachment 4. Growth 5. Partial detachment 6. Steady state 5.3.1.1

Phase Development

The six steps of biofilm development can be categorized into three phases based on the change in thickness of the biofilm. This is shown in Figure 5-5.

Figure 5-5 Typical Progression of Biofilm (courtesy of Biofilms by John Wiley & Sons, Inc.)

x

Phase 1 – Lag or Induction – Conditioning, transport, and attachment with little or no biofilm

x

Phase 2 – Logarithmic Growth (Log Accumulation) – Exponential growth in biofilm

x

Phase 3 – Plateau – Partial detachment and steady state – Large quantity of biofilm with constant thickness

Any biofouling control method must move the system from Phase 3 or Phase 2 solidly back into Phase 1. Because growth is explosive in Phase 2, cleaning that brings the system back only to Phase 2 or maintains the system at Phase 2 will lead to fouling again in a very short time. Intermittent flow or large velocity changes of the cooling water do not change the steps in biofilm development but they might change the rate of growth at different times. 5-15


Phase 1: Lag or Induction — Pioneer bacteria cannot adhere to a surface such as the interior of a condenser tube wall until organic molecules are transported from the bulk fluid such as cooling water to the substratum. Some of the organic molecules adsorb, resulting in a conditioned substratum. These adherent materials also provide nutrients for microorganisms that become lodged on the surface. Adsorption of an organic conditioning film is very rapid compared to the other biofilm processes. The microorganisms that become attached to the wall come in three waves. Rod-shaped bacteria are the first. These produce an environment conducive to attachment by other organisms. Bacteria of other shapes (stalked, budding, filamentous) follow. The third wave is other microorganisms such as protozoa and fungi. If protozoa are present in the cooling water and join the biofilm, they can reduce the accumulation of other organisms by feeding on them. Other debris, including the simple organic molecules needed for bacteria nutrition will continue to attach to the condenser tube walls during this wave. Phase 2: Logarithmic growth — No serious thermal, friction, or corrosion problems would result from the simple adhesion to metal surfaces of those few microorganisms present in the cooling water. However, those nutrients provided by the cooling water will allow the attached microorganism to feed and multiply. Given sufficient nutrient availability and a favorable surrounding temperature, bacteria can reproduce in 20 minutes to several hours. This exponential growth produces colonies of thousands of cells in one or two days. Phase 3: Plateau — Eventually the biofilm grows thick enough to partially slough off into the cooling water stream. A steady state or plateau phase is reached in which growth is balanced by detachment or sloughing caused by the shear stress of the flowing water. Biofilm thickness is an important characteristic in analyzing biofilm processes because thickness determines the diffusional distance that must be known in order to calculate fluid frictional resistance and heat transfer resistance. Accurate measurement of biofilm thickness is difficult. The biofilm thickness can vary considerably over a given substratum due to irregular morphological features of the biofilm. Variation in thickness can also be a function of biofilm age. Biofilm density can affect the ease of biofilm removal and the depth of biocide penetration. Accurate measurement of biofilm mass density is directly related to accurate thickness measurement. Biofilm mass densities have been reported as high as 6.55 lb./ft.³ (105 kg/m³) and as low as 0.624 lb./ft.³ (10 kg/m³). Within the biofilm, density can vary with depth. A black deposit on condenser tube walls might look like biofilm. It can be manganese deposits that produce a similar film. Precipitation of manganese dioxide can also lead to pitting corrosion. Although biofilms and manganese deposits look similar, biofilms can be removed more easily. Manganese films are not always the result of inorganic deposition. In many cases, the films are the direct result of bacterial action, particularly in freshwater. The bacteria on the surface of the pipe remove manganese from the water and oxidize it, creating the deposit.

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5.3.1.2

Developing Factors Key Technical Point Several factors are involved in the accumulation and development of the biofilm including surface conditions, water quality, fluid velocity, water temperature, and tube alloy.

Figure 5-6 illustrates the factors that influence or control biofilm development.

Figure 5-6 Biofilm Development Factors

Each of these biofilm development factors is described below. x

Surface Conditions – Compared to other factors, initial surface conditions appear to have a minor effect on biofilm formation. Roughness is the primary surface condition that might affect early stages of biofilm growth. Observations suggest that the net cell accumulation rate is greater on rougher surfaces, but this has not been quantified. The extent to which surface roughness influences biofilm formation might be limited to the induction period.

x

Water Quality – Water quality considerations include the presence of microorganisms and nutrients and other factors such as salinity. The planktonic bacteria and other microorganisms in the water cannot produce biofilm without attachment to and growth on the tube wall. Microorganisms derive energy from light, inorganic, or organic compounds. The majority of the microorganisms in a condenser biofilm use organic compounds to fuel their reproduction. The development of a biofilm is directly influenced by the organic carbon content of the water. Biofilm starvation occurs easily if the organic carbon content is too low. However, even low levels of organic carbon are adequate to support biofilm development if coupled with high flow rates. In addition to organic carbon, nitrogen, phosphorous, and phosphates must be present. Deficits in these nutrients can inhibit biofilm development.

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Suspended solids in the water can add to the nutrients. Nutrients in suspended solids are not usually as available as dissolved nutrients. Suspended solids also scour the walls and increase the shearing effect of water velocity on the steady state thickness of the biofilm. However, some suspended solids can deposit into the biofilm, adding to the mass loading and the difficulty of removing it. x

Fluid Velocity – Fluid velocity can have either a positive or a negative effect on biofilm development. Adequate water flow brings organisms and nutrients to the condenser walls. High velocity also increases detachment. Steady state conditions are a balance between nutrient loading and shear due to flow. Steady state biofilm mass is usually lower in high velocity systems because detachment is increased. Most condensers, however, are designed for operation at a specific maximum velocity. Therefore, velocity cannot be raised beyond a certain point for fouling control or the condenser will not achieve optimum heat rejection.

x

Water Temperature – Biofouling typically increases during the summer months. It is easy to conclude that increased water temperature causes this increased growth. While bacterial metabolism and growth increase in higher temperatures, the summer effect might also be due to increased nutrients in the large volumes of cooling water. Many plants increase their total cooling water flow through the summer. The increase in biofouling rate and extent due to increased water temperature is significant when the organic carbon availability also increases.

x

Tube Alloy – Typical condenser tube alloy materials such as copper nickel, titanium, stainless steel, and admiralty brass have been tested for their effect on biofilm formation. For biofouling, the materials rank as follows: copper nickel showing the slowest biofouling, then brass, then titanium, and stainless steel the fastest biofouling.

These results are not surprising because copper is toxic to bacteria. Although copper nickel and brass slow biofouling, these materials might experience higher corrosion rates than the total heat rate degradation. This is because corrosion plus biofouling might actually be greater with these alloys. Also, copper corrosion can release copper ions into the water, affecting the plant’s ability to meet water quality standards. Like surface roughness, the impact of material selection is greatest during the induction period. Once the biofilm is established and corrosion rates have decreased to steady state levels, the material is relatively unimportant. 5.3.2 Chemical Fouling Chemical fouling is the formation of a chemical deposit with poor heat transfer properties on the inside of the condenser tubes. Examples of these deposits include manganese, iron, silicon, calcium carbonate, and calcium phosphate. This can be referred to as crystalline fouling and occurs when the solubility of the salts is exceeded. The most common deposit is calcium carbonate and removal of this deposit might require special cleaning tools. The solubility limit for this compound decreases with increasing water temperature. This causes deposition as inlet circulating water heats up in the condenser. Generally, the largest deposits are found at the outlet end of a single pass condenser and in the last pass of a multipass condenser.

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Most cooling waters contain large quantities of suspended solids. Some of these particles will adhere to the tube wall. Particulate fouling occurs when small particles of matter attach themselves to the tube wall. Generally, there must already be a substrate of deposit material to which the particulates attach. The common substrate is bacterial slime. Once attached, the deposit layer accumulates rapidly with a corresponding decrease in the thermal heat transfer. The standard cooling water tube velocities of approximately 7 ft/sec (2 m/sec) are often high enough to remove new material at the same rate as it is deposited. An equilibrium condition is reached when no further deterioration in performance occurs. This fouling process has been termed asymptotic fouling. Off-line cleaning methods are commonly used to remove particulate fouling. Key Technical Point Chemical additives used for biological control or corrosion inhibition can also result in microfouling. For example, water containing manganese will react with chlorine to form manganese dioxide particles and substantially increase fouling risk. Copper alloys and 300 series stainless steels are likely to suffer significant corrosion under these circumstances.

5.4

Microfouling Chemical Treatment [15] Key Technical Point Several factors must be considered when using chemicals to control microfouling of main steam condenser cooling water systems. These factors include condenser cooling system design and operation, biocontrol agents, environmental regulations, chemical application methods, and safety and exposure.

5.4.1 Cooling System Design and Operation There are two basic types of utility condenser cooling systems: once-through and recirculating. In once-through cooling systems, cool water passes through the condenser and then discharges to a body of water without recycle or reuse. In recirculating cooling water systems, water passes through the condenser to a cooling tower or spray pond, where evaporation reduces the temperature before the water recycles back to the condenser. Some water is discharged from the system as blowdown and makeup water is added to offset evaporation and blowdown. The chemicals added to once-through systems are not recycled, thus limiting the type and amount of chemicals that can be discharged. A major advantage of recirculating systems is that the chemicals remain within the system continuously. This reduces the amounts needed for biofouling control and reduces the quantities discharged for the system. Both types of systems have chemical discharge limits but recirculating systems discharge a lower volume of chemicals and water than once-through systems. Also, restricting the discharge of cooling system blowdown for several hours to allow for reaction and decay of biocides can reduce chemical discharge levels substantially. Re-circulating systems, thus, have considerably more flexibility in terms of the types and amounts of chemical treatment that can be employed economically.

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5.4.2 Biocontrol Agents A chemical microbiological fouling control program consists of periodically adding one or several biocides to all of the water passing through the condenser. Biocides are chemicals that are toxic to organisms. Key Human Performance Point To be effective in controlling biofilm formation, all biocides require adequate dosage, contact time with the biomass, and frequent application. Generally, these toxic chemicals are grouped into two categories: oxidizing and non-oxidizing. 5.4.2.1

Oxidizing Biocides

Oxidizing biocides oxidize or break down the microfouling deposits by oxidizing the organic component of the microorganisms. This kills or deactivates the microorganisms. The most commonly used oxidizing biocide for condenser biofouling control is chlorine applied as a gas, liquid, or solid-release chemical. Other common oxidants are bromine (available from several chemicals) and chlorine dioxide. Table 5-1 compares the most common oxidizing biocides. Table 5-1 Commonly Used Oxidizing Biocides [15] Characteristic

Chlorine-Based

Bromine-Based

Chlorine Dioxide

Application Methods

Fed primarily as a gas or aqueous solution

Fed as aqueous solution or generated via oxidant reaction with bromide salt

Must be generated at the site and mixed with water

Dosage/Duration

Usually 0.2 mg/liter for two hours per day (four times for 30 minutes each)

Usually 0.1 mg/liter for two hours per day (four times for 30 minutes each)

A residual of 0.05-0.1 mg/liter for one hour per day (four times for 15 minutes each)

Cost-Effectiveness

Usually most costeffective

Generally 50-100% more costly than chlorine

Generally 700-800% more costly than chlorine

5.4.2.2

Non-Oxidizing Biocides

Non-oxidizing biocides are systemic poisons that kill the microbiological organisms by interfering with their metabolism. The non-oxidizing biocides do not remove the biomass. However, some of the dead biomass often sloughs off the heat transfer surfaces and is flushed from the tubes by the cooling water turbulence. There are many different non-oxidizing biocides and mixtures in a single product. Some typical non-oxidizing biocides are complex fatty acid quaternary ammonium compounds (known as quats), organic halogen compounds (such as

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brominated proprionamide), sulfur-based products (such as thiocarbamates), and organic chemicals containing several basic functional groups (such as isothiazolone). Many commercial non-oxidizing biocides are available for cooling water biofouling control. However, limited registration and/or toxicity persistence can prevent using them in all types of cooling systems. Many non-oxidizing biocides are not used in once-through cooling systems because of possible impact on the environment and discharge restrictions. Key Human Performance Point The biocide label lists restrictions that govern the use of the biocide for all applications. It also lists danger signs, environmental hazards, treatment methods, storage and disposal instructions, and how to apply initial and subsequent dosages. Non-oxidizing biocides often maintain their activity even after discharge from the system, while oxidizing biocides are usually consumed in minutes. Regulator limitations should be understood before using non-oxidizing biocides. Non-oxidizing biocides are usually liquids with several components: the active biocide or biocides, solubilizers, dilutants, and occasionally surfactants or wetting agents. Most are waterbased, although some are water dispersible slurries or in hydrocarbon solvents. All of these chemicals are toxic and often quite hazardous to handle. Each product Material Safety Data Sheet should be studied before use. Non-oxidizing biocides can be classified by their basic ingredients and chemical composition. See Table 5-2 for the types and examples of generic non-oxidizing biocides. Table 5-2 Typical Generic Non-Oxidizing Biocides [15] Type

Example

Nitrogen-based

Quats Quats and Organotins Amines

Sulfur-based

Thiocarbamates Thiocyanates

Halogen-based

Chloro phenois Bromo organics

Metallic-based

Copper salts Silver salts Organotins

Other

Aldehydes

Combinations

Isothiazolinone Chloro sulfones Triazines

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The specific ingredients of these chemicals and mixtures are registered with the Environmental Protection Agency (EPA). Several examples of non-oxidizing biocides are described below. The quaternary ammonium salts (quats), commonly used for condenser biofouling control, include: x

Methyl-dodecyl-benzyl-trimethyl ammonium chloride

x

Tetradecyl-dimethyl-benzyl ammonium chloride

x

N-dodecyl-guanidine hydrochloride

x

Poly-oxyethylene-dimethyliminio-ethylene-dimethyliminio-ethylene dichloride

Some of these chemicals can cause foam because they are surface active. They usually have a strong cationic charge that can react with commonly used anionic dispersants and/or scale inhibitors, which can reduce the effectiveness of both the biocide and the inhibitor. One of the sulfur-based biocides is methylene bis-thiocyanate, another non-oxidizing bromine. It is effective if the cooling water has a pH of 7.5 or less. Above that pH, it decomposes rapidly. Another sulfur-based biocide is dithiocarbamate, which is effective above a pH of 7.5, but is corrosive to copper alloys. Non-oxidizing biocides are used alone only when special conditions occur, such as when the condenser cooling water consumes large quantities of oxidants (due to high iron and/or manganese content, typical of mine drainage waters). However, such stand-alone non-oxidizing use is very specialized, even when treated sewage plant effluent (with a high oxidant demand) is used for condenser cooling water. Most commonly, non-oxidizing biocides are used to supplement an oxidizing biocide, for example, to control algae or sulfate-reducing bacteria. Because there are such a variety of non-oxidizing biocides from which to choose, it is imperative to know which class or classes of microorganisms can be controlled with each chemical. Plant engineers and chemists must be aware of the limits of adverse actions of these chemicals and base the application of these chemicals on knowledge of their effectiveness at a specific concentration and duration. This data can often be obtained from the supplier. 5.4.2.3

New Biocides

Several oxidants currently show promise for use in condenser biofouling control. These oxidants include hydrogen peroxide and ozone. However, these oxidants have had limited application and must be reviewed for site-specific application. In general, they are either too costly or have limited effectiveness for power plant use. Ultraviolet light is also an option for use as a biocide. Hydrogen Peroxide Hydrogen peroxide is a good biocide but it is not necessarily cost-effective. It is supplied as a liquid, usually as a 30% water solution. It is fed via a pump, similar to the sodium hypochlorite solution. It is a weaker oxidant than chlorine. Use levels are equivalent to chlorine, 0.5-1.0 mg/liter active oxidant, but effectiveness usually requires a minimum of twice the contact time. 5-22


After reaction, hydrogen peroxide is reduced to water and oxygen. Thus, from an environmental standpoint, this lack of regulated by-products is a major advantage. It is commonly used in highpurity systems for biocontrol. Ozone Ozone is currently being evaluated in small air-conditioning cooling systems. Ozone gas is produced by passing dry air or oxygen through an electric current or corona. The gas is dissolved in water and the solution is then injected into the cooling water. Dosages are usually less than 0.2 ppm oxidant, because higher levels can oxidize (corrode) other materials in the system. Ozone has very limited solubility in water, much like oxygen, and is easily stripped at the cooling tower. Ozone reacts quickly with many organics and biomass and it is quickly depleted. Ozone is often completely consumed and not detectable 10 minutes after injection. Multiple injection locations might be required. On the other hand, ozone decays to oxygen. The lack of residuals can be an environmental advantage. In general, ozone appears to not be cost-effective for utility plants, due to the high cost of generation and installation, rapid reaction, low solubility, and unpredictability of performance. However, studies continue to evaluate ozone for biofouling control. If it can also help control deposits and corrosion, it might be cost-effective in the future. Ultraviolet Light Ultraviolet light has very limited effectiveness. Special bulbs produce it and its strength is measured by the intensity of the lamp and the power input. However, it is active only as far as the light can penetrate and it does not penetrate turbid water. The water does not carry it, therefore it cannot clean condenser surfaces. 5.4.3 Water Regulations Key Human Performance Point The Environmental Protection Agency (EPA) and the states mandate three types of regulations governing the quality of discharges. They are technology-based regulations, historically based effluent water quality standards, and receiving water quality-based standards. 5.4.3.1

Technology-Based Regulations

Power plant discharges are currently regulated by the best available technology (BAT), best conventional technology (BCT), or best practicable technology (BPT). These limitations are either parameter-specific, covering parameters such as pH and the total suspended solids, or chemical species-specific, covering species such as total residual chlorine and total copper. Monitoring requirements are usually satisfied by grab or composite sampling and analysis at weekly or monthly intervals. Some discharge permits require continuous monitoring of total residual chlorine as a condition for allowing continuous chlorination for macroinvertebrate control. 5-23


Oxidizing biocides (chlorine, bromine, ozone, chlorine dioxide) are frequently regulated as a group in parallel fashion. Non-oxidizing biocides are not commonly used for microbiofouling control in once-through cooling systems for reasons of cost and toxicity. Their use in recirculated cooling systems is similarly limited, although to a lesser extent. In some recirculated systems, it might be possible to discontinue blowdown for a sufficient length of time to permit degradation of the biocide to levels acceptable for discharge. For chlorine best available technology, effluent limitations for once-through cooling water are 0.2 mg/liter maximum total residual chlorine. Further total residual chlorine might not be discharged from any single generating unit for more than two hours per day unless the generator demonstrates to the permitting authority that a longer discharge period is required for macrofouling control. The best conventional technology discharge limits for chlorination of once-through cooling systems are specified in terms of free available chlorine concentration during application: 0.5 mg/liter maximum free available chlorine and 0.2 mg/liter average free available chlorine. No single unit can discharge chlorine for more than two hours per day. No more than one unit at a plant can discharge at the same time. For all plants with cooling towers, the limits are the same. An exception might be made if the units in a particular location cannot operate at or below this level of chlorination. Both of these regulations are concerned with the chlorine content at the point of discharge from the plant. Usually free available chlorine is only a small fraction of total residual chlorine at the point of discharge. Therefore, the best available technology guidelines regulating total residual chlorine are far more stringent than the best practicable technology guidelines on free chlorine. These regulations are specified in Federal Regulations 40 CFR Parts 423.12 and 423.13 and are summarized in Table 5-3. Table 5-3 Technology-Based Regulations for Chlorine [15] Level of Control

Discharge Limitations

Covers

Time Limitations on Discharge

Best Available Technology

0.2 mg/liter maximum total residual chlorine

Once-through cooling systems with plant capacity > 25Mw.

2 hours per day per unit; simultaneous multi-unit chlorination permitted

Longer chlorination period might be allowed if macrofouling control is required

Best Practicable Technology

0.5 mg/liter maximum; 0.2 mg/liter average free available chlorine

Once-through cooling systems; recirculated cooling system blowdown

Two hours/day; one unit at a time

Utility might be able to demonstrate that units cannot operate at or below required level of chlorination

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Exceptions to Regulations


Key Human Performance Point In general, the technology-based regulations are species or compoundspecific numerical limits, either concentration or mass per unit time. These limitations are based on the performance of the best available technology on the particular category of effluent for a particular industry. These limitations are typically the least restrictive limits that can be imposed. 5.4.3.2

Historically Based Effluent Water Quality Standards

The historically based effluent water quality standards are usually chemical-specific (for example, chlorine or benzene) regional or statewide limits on the concentration of a discharged chemical. They have a historical rather than a precise mathematical relation to stream quality. They represent an amalgam of technological, water quality, social, political, and economic considerations. 5.4.3.3

Receiving Water Quality-Based Standards

The receiving water quality-based standards are directly related to the water quality requirements for the receiving water body. They can be stated in terms of chemical specific concentration units obtained by a designated analytical methodology. For example, a limitation might be that copper must not exceed 12 Pg/liter, measured as daily maximum by graphite furnace atomic absorption. Regulations might also be stated in terms of toxicity units derived from a designated wholeeffluent toxicity test conducted on the discharge. Unlike the best available technology and best practicable technology limits that generally must be measured directly at the discharge point, the water quality-based limits generally consider receiving water mixing characteristics. However, differences in acceptable dilution models can affect the allowable discharge from power plants. The criteria continuous concentration (CCC) and the criteria maximum concentration (CMC) for total residual chlorine that affects chlorine discharges are:

x CCC is the highest four-day average instream concentration of a toxicant that cannot be

exceeded more frequently than once in three years. The concentration must also be at or below the concentration that organisms can be exposed to indefinitely without causing an unacceptable effect. The CCC for chlorine is 11 Pg/liter total residual chlorine in receiving freshwater and 7.5 Pg/liter total residual chlorine in receiving saltwater outside of the mixing zone.

x CMC is the maximum one-hour average concentration above which organisms cannot be exposed without causing unacceptable mortality. The CMC limit cannot be exceeded more frequently than once in three years. The CMC limit for chlorine is 19 Pg/liter total residual chlorine that generally is applicable in receiving freshwater inside and outside of the mixing zone and 13 Pg/liter in receiving saltwater.

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The EPA establishes effluent guidelines and water quality criteria. Most state regulatory bodies use these guidelines and establish state water quality standards as a basis for issuing discharge permits. The states can also make guidelines and standards more restrictive if appropriate. Because state enforcement standards differ and some states do not have individual standards but are regulated under the water quality criteria set by the EPA, specific standards for all states cannot be listed here. 5.4.4 Chemical Application Methods For condenser biofouling control, biocides are usually applied periodically. The duration of the biocide feed varies considerably from site to site and even from unit to unit at the same plant site. This duration can be from very brief, intermittent feeds to continuous feed. In addition, application frequency and duration can vary seasonally due to water nutrient levels, temperature, and the organism loadings in the water and on the condenser tubes. The dosage and frequency must be at the level that will maintain efficient condenser operation while meeting applicable regulations for biocide discharge. The site-specific National Pollution Discharge Elimination System (NPDES) discharge limit is often the limiting factor in choosing the optimum biofouling control procedures for a particular site. However, a variance in procedure might be possible if the condensers are severely biofouled and/or the water supply is highly contaminated. Key Human Performance Point Oxidizing biocides are usually the primary biocontrol agents for oncethrough and recirculating condenser cooling water systems. Non-oxidizing biocides seldom are used in once-through condenser cooling water systems except for special applications such as macrofouling control. In recirculating cooling water systems, particularly cooling towers, a slug addition on nonoxidizing biocides is common as an assist or booster to the oxidizing biocide. This is used to control certain types of microbiological organisms not easily controlled with the oxidant. Sulfate-reducing bacteria, some algae and fungi are typical examples. The dosage is usually based on the system capacity. The frequency of addition might be weekly or less often. If the non-oxidizing biocide is the primary biocontrol then application and dosage might be greater. Because cooling tower systems recirculate and retain the cooling water, slug addition provides extended contact time with the biocide. Effectiveness of the biocide depends on its properties. These properties often are a function of system water pH, hardness, turbidity, the type of microorganisms, and degradation of the biocide within the system. Depending on the biocide and its toxicity, a detoxification step might be required before discharging treated waters from a recirculating system. Several different oxidizing biocides are used for controlling condenser biofouling. However, chlorine added as chlorine gas or sodium hypochlorite is the most commonly used biocide in power plant applications for control of fouling by microorganisms. Another oxidant, chlorine dioxide, is a special and specific compound quite different from chlorine. The other predominant 5-26


oxidizing biocides are bromine-based compounds. They have seen increasing use in utility application. Although ozone and hydrogen peroxide have been used occasionally for utility plant condenser treatment, they are rarely used. 5.4.4.1

Chlorine

Chlorine compounds typically are fed as aqueous solutions into the cooling water going to the condenser. This can be done immediately before the condenser or at any convenient location upstream of the condenser, such as at the cooling water pumps supplying water to the condenser. In a once-through system, the chlorine can be injected at the plant intake to ensure treatment of the intake line as well as the condenser. Chlorine can be supplied as a chlorine gas, sodium hypochlorite, and calcium hypochlorite. Chlorine gas is supplied as a liquid in pressurized 100-, 150-, and 200- pound (45.4, 68 and 90.7 kg) cylinders or, for larger amounts, in railroad tank cars. When cylinders are used in the power plant, several cylinders are often manifolded together to increase the time between cylinder changes. The pressurized liquid chlorine, which is 100% available chlorine, vaporizes to gas when released to atmospheric pressure at temperatures above 40qF (4.4qC). At lower temperatures, a heater is often used to obtain effective vaporization. Liquid chlorine can damage the chlorine feed system by backing up into the chlorinator as a water/gas mixture when only a dry gas is present. Key Human Performance Point Chlorine gas is very toxic and extremely irritating. It is a green vapor that is denser than air. Small leaks can be detected with a 10% solution of ammonia hydroxide. The chlorine and ammonia vapors form a white vapor of ammonium chloride. A typical chlorine gas feed schematic is shown in Figure 5-7.

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Figure 5-7 Chlorine Gas Feed Schematic [15]

The chlorine gas passes through a flow meter, and then is thoroughly mixed with water in an aspirator or water jet eductor. The resultant solution is usually several hundred parts per million of hypochlorous acid with some chlorine at a pH of 3 to 4. This concentrated hypochlorous acid solution is then fed to the cooling system where it is diluted with the cooling water to an effective biocidal concentration of a mixture of hypochlorous acid plus hypochlorite ion, with proportion depending on the final pH. Clean water, free of suspended solids, should be used to prevent feeder plugging. Concentrated cooling tower water used in the eductor should be avoided because many treatment chemicals can be totally degraded when contacted by the concentrated hypochlorous acid and low pH solution in the eductor. This is particularly true when organic chemicals such as copper, scale, and dispersant inhibitors are present. Chlorinators require regular maintenance to assure reliable, continuous use. Loss in chlorine feed for several days can result in rapid biomass buildup in the condenser. Key Human Performance Point Appropriate safety equipment such as chlorine gas masks should be available in case a leak occurs in feedlines or at cylinder connections. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions.

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Sodium hypochlorite is the second most commonly used source of chlorine. It is found as an alkaline water solution of sodium hypochlorite with several percent free caustic. This solution is made by reacting chlorine gas and sodium hydroxide, resulting in a very alkaline (pH 11-12) solution of 10-12% available chlorine. Higher concentrations such as 15-18% can be obtained, but they quickly reduce to 10-12%. Sodium hypochlorite solutions are not very stable. At altitudes above 4,000 feet (122 m), a 10% solution is common because chlorine vaporizes and reduces a 12% solution to a 10% solution within a few days. Sodium hypochlorite gradually emits chlorine regardless of altitude, especially at temperatures above 90qF (32qC). Lower concentration solutions of 5% and 8% are sometimes used for smaller systems. By comparison, household bleach is a sodium hypochlorite solution of approximately 5% available chlorine. Sodium hypochlorite solutions are most often added to the cooling water via a corrosion resistant pump in an area of good mixing or through a mixing chamber. Due to the highly alkaline hypochlorite solution, calcium scale can develop when using or injecting into high hardness waters. As with chlorine gas, if cooling water is used for mixing, the high chlorine concentration can degrade some of the water treatment chemical effectiveness. Thus, it is advisable to use freshwater for dilution to prevent this degradation. Sodium hypochlorite is a strong oxidant and a highly alkaline (free caustic) liquid that will cause skin and eye damage. Organic or cloth rags should not be placed in contact with sodium hypochlorite liquid. A rapid reaction (possible explosion) and/or spontaneous combustion can occur. Key Human Performance Point Appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment used to store or feed sodium hypochlorite. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions. A variety of dry products release chlorine. These products are not normally used as the primary chlorine source for biofouling control because of high cost. They are generally used as temporary or emergency substitutes when the regular supply of chlorine gas or sodium hypochlorite is exhausted or its feed equipment is inoperable. The most common dry product that releases chlorine is calcium hypochlorite Ca (OCL)2. Calcium hypochlorite is available in pellet (0.5-in to 1-in (1.3 to 2.5 cm) in diameter), granular, and powder forms and generally has 65% available chlorine. This product is produced by reacting lime (calcium oxide) with chlorine. When added to water, the dry product dissolves and releases both calcium and hypochlorite ions. It is added through a dry chemical feeding system or by spreading the dry product into the cooling water. Dry chlorine release chemicals are strong oxidants and any skin or eye contact can cause irritation or damage. The dust or powder is also very irritating to eyes, lungs, and skin.

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Key Human Performance Point Dry chlorine release chemicals are similar to dry bromine release chemicals. Appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment used to store or feed chlorine. A dust mask can also be used. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions. Table 5-4 summarizes the main methods of adding various chlorine compounds. Table 5-4 Chlorine-Based Oxidizing Biocides [15] Biocide

Chemical Makeup

Form

Application Methods

Delivery Methods

Chemical Reactions

Chlorine Gas

100% Chlorine

Liquid gas under pressure

Mixed with water and fed as aqueous solution

Pressurized 100,150, 200 lb. (45, 68, 91 kg) cylinders or railroad tank cars

Vaporizes to gas; reacts with cooling water to form hypochlorous acid and hypochlorite ion, proportion depending on pH

Sodium Hypochlorite

NaOCl, made of chlorine gas and sodium hydroxide, usually 1012% active chlorine

Liquid

Mixed with water or fed as concentrate

55 gallon (208 liter) drums, truck or railroad tank cars, or tote bins

Reacts with cooling water to form hypochlorous acid and hypochlorite ion, proportion depending on pH

Calcium Hypochlorite

Ca(OCl)2, 65% active chlorine

Dry: pellet, granular or powder form

Broadcast into an open flume or cooling tower deck or mixed with water and fed as an aqueous solution

50 or 100 lb (23 or 45 kg) drums

Reacts with cooling water to form hypochlorous acid and hypochlorite ion, proportion depending on pH

The targeted treatment technique was developed to maintain condenser biofouling control while complying with very strict chlorine limits in the condenser cooling water discharge. Although the targeted treatment technique can be used with a variety of chemicals, the usage to date has been with chlorine and is called targeted chlorination. Targeted chlorination consists of initially making several penetrations in the condenser waterbox to install delivery piping. Software is available from EPRI to determine the appropriate configurations and number of pipes. The pipe delivers high levels of chlorine at 10-20 ppm at the 5-30


nozzle that becomes diluted to 1-2 ppm at the condenser tubesheet. The chlorine treatment is applied sequentially to a small portion of the condenser tubes (10% or fewer of the tubes in the entire condenser) in the inlet waterbox for a short period, such as five to ten minutes. Mixing and diluting the discharge from these tubes with discharge from the other 90% untreated tubes assures compliance with environmental limits at the cooling system discharge. The following designs have been tested at full scale: fixed piping, moving-manifold, and tubesheet manifold injection systems (each tube individually treated). The generic form of this method allows any water-soluble chemical, not just chlorine, to be injected in this manner. This technique can offer an additional option to plants that have severe fouling but have stringent discharge limitations. Corrosion and materials compatibility, however, is an important site- and chemical-specific issue that needs to be addressed before this method is employed. Currently, the fixed pipe design is in commercial use at several power plants. For more discussion on the EPRI product, see Section 5.6 of this guide. 5.4.4.2

Bromine

Bromine-based oxidizing biocides release bromine species into the cooling water. These species are hypobromous acid and/or hypobromite ions. The pH of the cooling water determines the ratio in which bromine species are produced. The pH-determined ratios are different for bromine and chlorine. At the typical pH levels found in condenser cooling water (6-9), bromine produces more of the acidic species than chlorine. With bromine, at a pH of 9.0, the cooling water contains 80% hypobromous acid. At the same pH, chlorine would form only 10% hypochlorous acid. The acid form of chlorine is the stronger oxidant and is a much more effective biocide than hypochlorite ion. The hypobromous and hypobromite ions are very nearly equal in effectiveness and approach hypochlorous acid activity. Thus, bromine has become a more attractive option for condenser cooling waters in the pH range of 7.5-8.5. The bromine species have an advantage over the chlorine species in terms of reactions with ammonia. Bromoamines formed in this reaction are much more active as biocides than their chlorine equivalents and are almost as potent a biocide as the hypobromite ion. Thus, lower levels of bromine are being used for biofouling control. The bromine level used is often half the equivalent free available chlorine level used. This can partially offset the added expense of bromine over chlorine. At times, control can be maintained with combined bromine species (bromoamines) with no free available halogen. Bromine-release compounds, which include bromine and bromine chloride are liquids, very strong oxidants, toxic and extremely irritating. They release bromine, which is a brown, heavy gas that is also a strong oxidant, toxic, and extremely irritating. Sodium and calcium bromide, which are used to generate bromine, are generally considered only mildly irritating, non-toxic liquids because they are generally water solutions of salts. However, as with any chemical, general precautions with handling should be observed. Dry bromine-release chemicals are similar to dry chlorine-release chemicals.

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Key Human Performance Point Appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment used to store or feed bromine compounds. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions. Environmental regulations currently limit bromine species levels in plant discharge water to the same levels as chlorine. These regulations are site-specific and are often expressed as limits in total residual halogen or total residual oxidant, which includes both the bromine and chlorine species. A variety of bromine or bromine-release chemicals have been used for utility condenser biofouling control: x

Bromine liquid

x

Bromine chloride liquid

x

Sodium or calcium bromide activated by chlorine gas or sodium hypochlorite

x

Bromo, chloro hydantoins

Though they are often the most cost-effective of the bromine compound, bromine and bromine chloride have seen limited use for condenser biofouling control because of handling, feeding, and safety concerns. Activating a bromide salt by a chlorine compound (usually chlorine gas or sodium hypochlorite) has become the more popular method of producing the bromine species, hypobromous acid and hypobromite ion. Dry bromine-release chemicals are the hydantoins. They are often used in smaller utility plants but can be used in large utility condenser cooling systems where special conditions enable them to be cost-effective. Table 5-5 compares the various bromine compounds used for condenser biofouling control.

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Chemical Makeup

100% active bromine

BrCl, active bromine/active chlorine compound; 55% active bromine

1,1-bromo, chloro, 2dimethyl (or methylethyl) hydantoin, 35-45% active bromine

NaBr or Ca Br2

Biocide

Bromine Liquid

Bromine Chloride Liquid

Bromo chloro hydantoins

Sodium or Calcium Bromide

Dry (100%) or 40-45% water solution

Dry: pellet, granular, or stick form

Liquid

Liquid

Form

As concentrated product without dilution;thru diffuser or disperser

Combination storage and chemical feeder

As concentrated product without dilution; through diffuser or disperser

Through feeder similar to chlorine gas feeder

Application Methods

Table 5-5 Bromine-Based Oxidizing Biocides and Biocide Precursors [15]


Liquid: 55-gal. (208 liters)

Dry: 100-lb. (45 kg) containers

40-lb. (18 kg) plastic pails to 1500-lb. (680 kg) tote bins

Pressurized 2000 lb. (907 kg) containers

Pressurized 2000 lb. (907 kg) containers

Delivery Methods

5-33

Forms hypobromous acid or hypobromite ion

Dissolves in water to form hypobromous acid or hypobromite ion

Reacts in water to form hypobromous and hypochlorous acids

Forms hypobromous acid or hypobromite ion

Chemical Reactions

Fouling


Bromine compounds can be the most cost-effective oxidant if the cooling water is high in pH (above 7.5) and/or if ammonia compounds are present (above 2.0 mg/liter). Of the bromine compounds, bromine liquid has the greatest concentration of the active ingredient (100%). However, a measure of cost-effectiveness must also consider handling, safety, feeding, and storage. 5.4.4.3

Non-Oxidizing Biocides

Non-oxidizing biocides are most often applied either as a short (less than one hour) continuous feed or a slug feed (added within a few minutes). These parameters are shown on the product label and are strictly regulated. Application is often made with a chemical pump to the cooling water. Common application dosages based on system capacity or water flow, range from 5 mg/liter to 100 mg/liter depending on biocide effectiveness. The duration varies with the killing power, often ranging from several minutes to several days of biocide contact with the biomass. The frequency varies with the biocide and can be as often as every day or as rarely as once per month, or irregularly, on an as-needed basis. Guidelines are provided by biocide suppliers and are printed on product labels. Some examples for various cooling systems are listed in Table 5-6. Table 5-6 Application of Non-Oxidizing Biocides [15] Type of Cooling System

Dosage

Duration

Frequency

Once-through

5 mg/liter based on the flow of the product

15 minutes continuous application

Daily

Recirculating

20 mg/liter based on system capacity

20 minutes with biocide effective for 12 hours

Once every two weeks

Key O&M Cost Point Most non-oxidizing biocide applications are much more expensive than oxidizing biocides, but site-specific conditions could change this. Generally, non-oxidizing biocides are applied once per week or several times per month, as compared to several times daily for the oxidants. Few convenient field tests exist for measuring non-oxidizing biocides. Most non-oxidizing biocides require specific laboratory analysis procedures. Most techniques for monitoring nonoxidizing biocides focus on their effectiveness in keeping an acceptably low level of microorganisms in the cooling water or maintaining the condenser free of biomass, not on the specific chemical. Thus, monitoring condenser cleanliness is the primary emphasis. Toxic discharge is also a criterion to be evaluated when using a non-oxidizing biocide.

5-34


Key Human Performance Point For non-oxidizing biocides, appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment used to store or feed the chemicals. Some of the non-oxidizing biocides are extremely irritating. They can penetrate clothing, shoes, or leather and are rapidly absorbed through the skin. Some emit toxic irritating vapors. Great care should be taken in handling all non-oxidizing biocides. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions. Key Human Performance Point Biocides are regulated by the EPA. Each biocide must be registered for a specific use such as microbiological control. In addition, it must be registered for the specific cooling water systems in which it can be used. The container label must specify a variety of information, including at a minimum, the percent of each active component, product use instructions, safety handling precautions, EPA registration number, and the EPA manufacturing location number. It is a federal violation to use a chemical in any manner other than its intended purpose or at any dosage/duration/frequency not specified on the label. Because all biocides are potentially dangerous, it is important to have the safety, handling, and disposal procedures ready before receiving the chemicals. Personnel should be thoroughly trained to work with and handle these substances safely. Biocide suppliers should provide the Occupational Safety and Health Administration (OSHA) and Material Safety Data Sheet (MSDS) forms before on-site delivery. Plant personnel should read, understand, and implement proper storage and handling precautions before receiving the chemical. This information should be posted on the storage container and near the location where it will be used.

5.5

Fouling Monitor [16]

EPRI has developed a monitoring system that provides direct on-line measurement of condenser fouling. Using probes installed at one or more locations within a condenser, the condenser fouling monitor (CFM) provides more accurate heat transfer data than is provided by other approaches. The CFM uses one or more pairs of adjacent tubes in the operating condenser and extensions of those tubes mounted on the outlet tubesheet (see Figure 5-8). One tube in each pair remains open (active). The other (inactive) tube is plugged and used to measure inlet water temperature and saturated steam temperature. Flow and temperature sensors are attached to an extension of the active tube, to measure outlet water temperature and flow velocity. Signals from the flow and temperature sensors are transmitted to a data acquisition system for storage and processing.

5-35


Figure 5-8 EPRI Fouling Monitor [16]

Using the measured flow rate, inlet and outlet water temperatures, and saturated steam temperature, the system calculates the heat transfer coefficient. The CFM determines the extent of tube fouling by comparing the calculated heat transfer coefficient to the highest heat transfer coefficient achievable if the tube were in the same physical condition as that following the latest cleaning. The CFM has been installed at three power plants.

5.6

Targeted Chlorination With Fixed Nozzles [17]

Targeted chlorination uses fixed nozzles to apply relatively high doses of chlorine solution (0.6 to 2 ppm) to selected areas (8 to 12 sections) of the condenser inlet tubesheet for short periods (5 to 10 minutes). The solution is sequentially injected through fixed nozzles onto fractional areas of the tubesheet until the entire tubesheet has been chlorinated. This method effectively controls biofouling and dramatically reduces chlorine consumption up to 80 percent. The effectiveness of bulk chlorination has been significantly reduced for once-through cooling systems since the EPA lowered the allowable discharge concentrations of chlorine residuals to 0.2 mg/liter total residual chlorine and restricted discharge to 2 hours/day per unit. The full-scale demonstration of the fixed-nozzle design at New England Power's Brayton Point Station Unit 2 Condenser showed the technology to be more effective at maintaining condenser cleanliness than the conventional bulk chlorination method.

5-36


6 CLEANING [15]

The primary objective of cleaning is to remove corrosion, fouling, and scaling material from the inner surface of the condenser tubes to bring heat transfer performance back to specification. Key Technical Point Some performance parameters that indicate condenser cleaning is needed are increased condenser backpressure, decreasing cleanliness factor, decrease in inlet and outlet cooling water temperature difference, heat rate increase, and megawatt output decrease. Recent chemical cleanings at two Exelon plants, Braidwood and LaSalle, resulted in significant improvements in generating capacity. Braidwood Units 1 and 2 were cleaned with the chemical Ferroquest LP7202 with a gain of 5 and 7 megawatts, respectively, after the cleaning. Before and after cleaning pictures are shown in Figures 6-1 and 6-2.

Figure 6-1 Braidwood Unit 1 Before Cleaning [18]

6-1

EPRI Licensed Material Cleaning [15]

Figure 6-2 Braidwood Unit 1 After Cleaning [18]

Clinton Nuclear Station had calcium carbonate scale deposits in their condenser tubes. The tubes were cleaned with cutters and scrapers and regained 20 Mw lost from the condenser performance. Peach Bottom Nuclear Station had manganese deposits in the condenser tubes. Mechanical scrapers were used to clean the tubes and the unit regained 25 Mw lost from the condenser performance. For more details on the Mw recovery of these units, see “Improved Condenser Performance Can Recover Up to 25 Mw Capacity in a Nuclear Plant” [19]. The two types of available cleaning applications are on-line and off-line. This section focuses on the mechanical and chemical cleaning options that are available in the industry. Key Technical Point The on-line cleaning techniques include the sponge ball system, brush and cage system, abrasive cleaning and self-aligning rockets. These systems can require a large capital investment. A continuous cleaning system offers the advantage of keeping the tubes clean without any fouling buildup. Some additional maintenance and operations attention is required. The constant scraping of the tube inside walls can cause tube thinning.

6-2


Key Technical Point The off-line cleaning techniques include the use of brushes, scrapers and hydroblasting. The equipment costs for these systems are relatively inexpensive. The unit must be derated or off-line in order to clean the tubes. Tube cleaning can be scheduled during refueling/boiler outages or during a scheduled load reduction. The cleaning process requires an operator and the air and water pressures used can impose a safety concern. Each type of off-line cleaning system has limitations. Brushes are effective with the soft fouling deposits. Metal scrapers and high-pressure water lances are more effective with harder scale deposits. In some instances, it is necessary to chemically clean the tubes and then use mechanical devices to remove deposits. Some characteristics of on-line techniques are: x

Require a comparatively large capital investment.

x

Clean a thin layer of foulant with each pass so foulant cannot build up.

x

No interruption in service is required.

x

Continuous cleaning of each tube can lessen the need for biofouling chemicals.

x

Require limited maintenance and operator attendance.

x

Constant wiping action of balls can remove tube wall material; brushes scrape the inner surfaces of the tube, removing material and possibly reducing wall thickness.

x

Balls must be inspected and replaced frequently and broken or abraded balls must be removed.

x

Balls can be stopped by debris and can plug up tubes.

Some characteristics of off-line techniques are: x

Equipment cost is low.

x

Tube cleanliness might begin to deteriorate as soon as tube cleaning is complete.

x

Full or partial interruption in service is needed.

x

Fouling can take on different characteristics so the scraper or high-pressure water might have to deal with a hardened, tightly adherent material that is difficult to remove.

x

Require an operator or a technician during cleaning. Some equipment poses a safety hazard due to the high water or air/water pressures that propel cleaning devices through the tubes.

x

Lances, rotating scrapers, and brushes can gouge and damage tube walls if they are used aggressively and/or incorrectly.

x

Only water lance systems don't wear out or require periodic replacement, however, consumables must be purchased per cleaning event. 6-3


The successful diagnosis and resolution of condenser performance problems related to fouling is based on the identification of the fouling mechanisms and the corresponding effective cleaning technology. The effectiveness of the cleaning technology applied and the heat transfer loss from the deposits varies dramatically from site to site. Common investigative methods for fouling determination include the use of fouling monitors, sampling of the tube deposits, and single tube heat transfer testing. The single tube heat transfer testing involves extracting a tube from the condenser, measuring the heat transfer coefficient, cleaning the tube, and re-measuring the heat transfer coefficient. The results of this testing have been used to verify the condenser performance testing, assist in locating the source of the performance loss, optimize the cleaning methods, and monitor performance of cooling water chemical treatment methods. For more information on these techniques, please see “Diagnostic Technique for the Assessment of Tube Fouling Characteristics and Innovation of Cleaning Technology” [20]. No one technique for cleaning biofouling is ideal under all conditions. Sometimes chemical cleaning is required to complement mechanical cleaning or vice versa. Chemical cleaning might be needed to reduce the fouling thickness followed by mechanical cleaning with scrapers or high-pressure water lances to remove the remaining fouling thickness. Chemical biocide treatment might be needed to disinfect copper-alloy tubes from bacterial attack, supplementing a ball cleaning or brush cleaning technique. Many utilities that use on-line ball cleaning also use brushes or water lances during outages to remove debris or tenacious films on the tubes. These films might not be biological but rather corrosion products, mussels, or debris.

6.1

Mechanical On-Line Cleaning Systems [15]

Condenser on-line cleaning systems include: x

Sponge ball system

x

Brush and cage system

x

Self-Aligning rockets

Generally, on-line cleaning systems offer the advantage of reducing unit downtime. However, installation of some of the cleaning systems is capital intensive. 6.1.1 Sponge Ball System Ball systems use the cooling water flow to push or force slightly over-sized sponge rubber balls through the condenser tubes. This action provides a continuous wiping action against the inner tube walls. Figure 6-3 shows a typical ball cleaning system developed in Germany and modified by French, Japanese, and American companies.

6-4


Figure 6-3 Typical Ball Cleaning System [15]

This sponge ball cleaning system includes three steps: ball injection, tube cleaning, and ball collection and return for re-injection. Ball Injection — The balls are injected into the circulating water upstream of the condenser inlet, most commonly in an elbow bend, as shown in Figure 6-3. To provide good ball dispersal, injection is against the direction of inlet cooling water flow. When deaerated, the balls are approximately the same density as the cooling water. They should enter the tubes randomly so that no section of tubes will be preferentially cleaned or neglected. A charge of balls equal to 515% of the number of condenser tubes per pass is sufficient to maintain cleanliness. With this ball count and continuous injection, each tube is expected to receive a cleaning ball about once every five to ten minutes. Tube Cleaning — Experience shows that the actual physical distribution of balls might not be uniform. This can lead to inadequate cleaning or excessive wear of some tubes. This depends on tube material and cooling water conductivity. The ball distribution is affected by the location of ball injection and by the flow patterns in the inlet waterbox. A ball cleaning system can also deal with strongly attached foulants by replacing some of the normal sponge rubber balls with balls that have an abrasive coating bonded to them. Granulate rubber balls have also been used to maintain the cleanliness of titanium tubes without scratching the tubes. When the foulant has been removed, normal service with plain sponge balls can

6-5


resume. This practice must be monitored closely because of potentially rapid erosion of copperalloy tubes by the abrasive balls. The constant wiping action of the balls can also remove tube oxide coating and wall material. Overcleaning soft base metals, such as copper alloys, results in erosion/corrosion of the tubes in high-conductivity cooling water. Overcleaning tubes removes the protective film. Undercleaning may leave a thick film that can inhibit heat transfer. The erosion/corrosion of copper-alloy tubes and the action of ball cleaning might produce trace metal effluents that affect water quality standards. Because of their inherent toxicity, copperalloy condenser tubes are less susceptible to biofouling than stainless steel or titanium tubes. Using copper-alloy tubes in clean seawater requires less sponge ball cleaning to maintain optimum cleanliness and tube service life. Under these conditions, one cleaning cycle per week should be sufficient. If the seawater is polluted or contains specific fouling agents that could produce pitting or other localized corrosion, the sponge ball cleaning frequency might have to be increased to prevent under-deposit corrosion. Ball Collection and Return for Re-injection — After the balls have traveled through the condenser tubes, they must be caught without impeding the flow of water. They are caught by a specially designed strainer system mounted downstream of the cooling water outlet waterbox. The balls are then discharged to the ball collection by recirculation pumps. At the collector unit, the operator can visually inspect the balls, manually size them, and replace any under-size balls. Balls flow from the collector unit to the injection locations at the inlet waterbox, where the cycle begins again. Operators use a round pan with appropriately sized holes to check the dimensional tolerance. New balls must achieve the right density to operate properly. They must be deaerated by agitation in the collector using the ball recirculation pump before release into circulation. These operations are labor intensive requiring about two hours by one operator every week or two weeks. Many users replace all balls without sizing based on an average ball lifetime determined from experience. This reduces the labor required to operate the system. The ball strainer can become clogged with debris or undersized balls. When the differential pressure across the strainer becomes high, it is back-flushed into the cooling water discharge section. The ball cleaning system is quite susceptible to the introduction of debris. If debris clogs or obstructs the tubesheet at the inlet waterbox, the tubes cannot receive cleaning balls. If debris lodges within a tube, there is a high probability that the tube will further plug with balls and/or more debris. Ball system manufacturers and others supply a number of upstream debris filter designs that address this problem. The debris filter systems can add significantly to the condenser capital cost. Because of the additional pressure drop across the debris filter, the circulating pump motor power consumption can increase. This causes higher operating costs. The capital costs of the sponge ball system and the increased maintenance costs must be compared to heat rate improvements from cleaner tubes and tubesheets.

6-6


For existing systems, space and outlet piping configurations can influence the retrofit of a ball cleaning system. If debris affects the effectiveness of the ball system and a filter is required then space limitations at the inlet piping and in the condenser waterbox should be considered. The outlet piping affects the location, design, and cost of the ball collection strainer. All remaining system components (small pumps, collectors, valves, etc.) can be installed wherever space exists. Inlet piping, waterbox design, and the resultant hydrodynamics affect the location and number of ball injectors required. A retrofit of the new designs is feasible except in difficult applications where the inlet and outlet piping are embedded in concrete. The greatest source of dissatisfaction among sponge ball cleaning system users has been the cost associated with system operation and maintenance. The piping systems, valves, and plugs can experience accelerated corrosion. The linkages of the older designs become loose and the instrumentation and controls require maintenance. Ball wear is a normal condition resulting in the loss of under-size balls that pass through strainer catch screens. Full-size balls can lodge behind debris or collection grids and become lost after a routine backwash operation. Ball hiding occurs at stagnation points in waterboxes and other areas where low fluid velocity allows balls to stop moving. As the strainer section screen condition deteriorates, the balls are easily lost. Key Human Performance Point Ball replacement is a normal operating cost associated with proper system operation. The manufacturers normally recommend replacing a complete charge of balls approximately once a month because of ball wear. Historical operating data show that ball usage is often much higher. New designs might be an improvement in ball life. Strainer design is crucial to successful operation. Over time, strainers become clogged with debris, undersize balls, or ball fragments. A differential pressure measuring system can be installed on the strainer section to indicate debris loading and to initiate a screen backwash procedure. This would occur if a predetermined differential pressure was reached. Some designs backwash by canting the screens. Trapped debris is then flushed from the front side of the screen and out to the cooling water discharge destination. The strainer screens are then returned to their normal operating orientation. The primary disadvantage of the older design multiple screen strainer is the large number of moving parts in the upper screens, lower screens, shut-off flaps, and throttle flaps. All of these are shaft-mounted and operated via linkages and mechanisms from outside the strainer section. Failure of any of these movable parts will eventually lead to significant ball loss and maintenance effort. The moving parts are actuated by both motor and mechanical operators. The operators require periodic maintenance and replacement. Figure 6-4 shows the older design strainer system.

6-7


Figure 6-4 Older Design Ball Strainer System [15]

The newer, simpler design is shown in Figure 6-5. This design uses a ball recovery system based on a stationary extraction block with small hydrofoils installed at the apex of the screens. The hydrofoils create small, localized vortices that remove the balls from the screen surface and keep them in suspension until they reach one of the extraction ports located at various points along the extraction blocks. This type of design has fewer moving parts. The multi-screen strainer design can be modified to the simplified dual-screen strainer design. This modification is cost-effective if the existing upper screens are in good condition or require only minor repair. If extensive repairs are required for the upper screens, replacing the strainer with a newer design might not be cost-effective.

6-8


Figure 6-5 Newer Design Ball Strainer System [15]

One type of ball recirculation system (Figure 6-6) requires re-injection pumps that remove the balls from one half of the strainer section and inject them into the other half. Other pumps are used to extract all the balls from the strainer section and circulate them through the collectors to the condenser inlet. They are then re-injected into the incoming cooling water.

6-9


Figure 6-6 Sponge Ball Recirculation System [15]

Piping systems can be simplified by re-piping from the strainer section to the suction side of the ball re-circulation pumps and increasing the impeller size within these pumps. This could result in redundant pumps, each capable of circulating all the balls if repairs are required. Automatic ball recirculation monitors can sound an alarm if ball circulation falls below a pre-set value.

6-10


There are advantages and disadvantages in using the sponge ball cleaning system. Some of the advantages of the sponge ball cleaning system are: x

Continuous cleaning of the tubes

x

Reduction or elimination of the need for biofouling chemical addition

x

Reduction or elimination of shutdown for manual cleaning

x

Operation is automatic

x

System can prevent under-deposit pit corrosion

x

Start-up costs are lower than for brush and cage systems

x

Different balls are available for different foulants

x

Condenser efficiency can be greatly improved

Some of the disadvantages of the sponge ball cleaning system are: x

Labor required for frequent ball inspection and replacement.

x

Adjustments to mechanized system components and controls are required.

x

There is tube abrasion of soft metals.

x

Operating costs are higher due to increased maintenance, auxiliary power consumption, and ball replacement.

x

System is susceptible to the introduction of debris.

x

Capturing balls can be problematic. A major escape of balls into a body of water can cause problems.

x

An uneven distribution of balls might not clean tubes uniformly.

x

Space and outlet piping configurations can influence retrofit.

x

Balls can become lodged in tubes, causing blockage.

x

Collection screens might experience fouling that increases water side pressure.

6.1.2 Brush and Cage System Another on-line condenser tube-cleaning method is the brush and cage system. This is used by some large power plants, smaller power plants, cogeneration plants, industrial heat exchangers and refrigeration chillers. A typical arrangement is shown schematically in Figure 6-7. In this arrangement, a captive brush is shuttled back and forth through each condenser tube by reversing the direction of flow through the condenser. Flow reversal requires appropriate valves and piping.

6-11


Figure 6-7 Typical Brush and Cage System [15]

There are several ways to install this flow-reversal mechanism. The type of flow diverters used depends on the site piping configuration. There is no need for a strainer; the cleaning brushes are caught by nylon cages attached to each tube end with epoxy or screws. The epoxied cages break off easily but are easy to repair. Flow reversal is usually initiated automatically on a timed cycle but remote manual operation is also possible from the system control panel. The brush and cage system requires limited maintenance or operator attendance. Other than the flow-reversal valves and the brushes, there are no moving parts. The brushes are usually guaranteed for five years. For a typical large power plant condenser it is recommended that approximately 500 spare brushes and cages be purchased to replace units that might fall off the tube ends. Large debris in the waterboxes can result in loss of brushes and serious damage to the cages. Figure 6-8 shows a typical arrangement for the brush and cage.

6-12


Figure 6-8 Typical Arrangement for a Brush and Cage Tube Cleaning System [4]

The most significant area of concern for potential users of the brush and cage system is the need for an expensive flow-reversal system, particularly in large steam condenser applications. Reversal of established cooling water could cause: x

Hydraulic transients in the system

x

Transient decrease in heat transfer rate

x

Transient rise in condenser backpressure

x

Drop in turbine-generator output

Some advantages of the brush and cage system are: x

Elimination of shutdown for manual cleaning but might require load reduction for backwashing

x

Ensures cleaning of each tube

x

Except for flow-reversal valves and brushes, no moving parts

x

Low operation and maintenance costs

x

Limited operations and maintenance personnel attention

x

Good at removing soft fouling material

x

Reduces/eliminates need for biofouling chemicals

x

Split condensers and two-pass condensers can be accommodated

Some disadvantages of the brush and cage system are: x

Reverse-flow piping and valves required

x

More susceptible to debris lodging in cages and restricting flow

x

Tube leak detection difficult because cages obstruct tube ends

x

Used in straight tubes only

6-13


x

Initial capital cost is high but lower than the sponge ball cleaning systems

x

Imprecise cleaning throughout the tube

x

Unit must be shutdown for the brush and cage replacement

x

Requires high tube velocities for effective cleaning

6.1.3 Self-Aligning Rockets This system consists of on-line mechanical tube cleaner rockets (see Figure 6-9) and a tube cleaner recovery system. The tube cleaner rockets consist of a two-part construction. The body is made of hard wear-resistant material that provides long life. The cleaning element, an elastometric disk, determines the level of cleaning and can be made of abrasive material, if required. The self-aligning design of the body helps with passage through the tubes. The rockets can be hydraulically injected into the suction of the circulating water pumps (Figure 6-10). This ensures even distribution throughout the volume of the cooling water. The recovery system simply consists of modified oil spill recovery booms, a tube cleaner recovery unit, and a means to recirculate the recovered cleaners. In most cases, the cleaners can be hydraulically conveyed to the injection point. After the cleaners are discharged into the canal, the tube cleaners will gradually rise to the surface. Once on the surface, the system of skimming booms channel the cleaners to a common collection point for recovery. The recovery is a pontoon-mounted traveling screen. It retrieves the cleaners, rejects the floating debris, and carries the cleaners to shore for inspection and re-injection.

Figure 6-9 Tube Cleaning Rocket [4]

6-14


Figure 6-10 Tube Cleaning Rocket Injection System [4]

The primary advantage of this system is that no permanent, expensive installation is required. Experience with this system, however, is limited. One type of self-aligning rocket, trade name Sidtec Rockets, has been successfully used by TU Electric in their Martin Lake Fossil Station.

6.2

Mechanical Off-Line Cleaning Systems [15]

Many off-line cleaning systems are available. All methods are manual and require full or partial outage of the condenser. Typical off-line cleaning methods and their effectiveness are outlined in Table 6-1. Table 6-1 Typical Off-Line Cleaning Methods and Their Effectiveness Off-Line Cleaning Methods Type of Fouling

Brushes

Scrapers

Hydro-Blasting

Chemical Cleaning

Severe Scale

Not Effective

Good

Fair

Good

Organic Growth, Mud, Slime

Good

Good

Fair

Not Effective

Shells

Not Effective

Good

Not Effective

Not Effective

The method of cleaning should be evaluated for the tube material, type of deposit, and cleaning time required.

6-15


The most common types of off-line tube-cleaning equipment are: x

Air/water-driven systems (bristly brushes, air/water, pigs, scrapers)

x

Mechanically driven systems (rotating brushes)

x

Pressure-driven systems (water lances)

A sample mechanical tube cleaning procedure, developed by Conco Systems, Inc., is presented in Appendix B. In addition, a confined space permit might be required when working in the waterbox. 6.2.1 Air/Water-Driven Systems One of the simplest off-line tube cleaning methods uses a bristle brush quite similar to (but with denser bristles than) the brush used in the on-line tube cleaning system. The cleaning brush is inserted into one end of a dirty tube and propelled through with a blast of compressed air, pressurized water, or a combination of the two. Removed material is flushed out along with the propelling medium as the brush moves along the tube and into the outlet waterbox. Brushes with nylon or metallic bristles can be used, depending on the nature of the fouling. Figure 6-11 shows a typical water-driven bristle brush and Figure 6-12 shows a propellant gun. Soft rubber plugs or plastic scrapers can be used in place of brushes if fouling conditions warrant. Another method is simply shooting 200-400 psi (1.38-2.76 megapascals) of air and/or water through the tube. This is the fastest method but is not appropriate for most cleaning.

Figure 6-11 Typical Water Bristle Brushes (courtesy of Conco Systems, Inc.)

Figure 6-12 Water Gun for Brushes and Scrapers (courtesy of Conco Systems, Inc.)

6-16


If the foulant is too hard to be removed by bristle brushes, then scrapers can be used. These are driven with 200-400 psi (1.38-2.76 megapascals) of water pressure. Scraping edges should be spring-loaded to match the specified tube diameter. There are two types of scrapers—plastic and metal. A picture of a plastic scraper is shown in Figure 6-13. Metal scrapers are shown in Figure 6-14. Scrapers have one or more rims that expand to conform to the shape of the tube. The scraping edges are spring-loaded to press against the tube surface. The scrapers are propelled by water.

Figure 6-13 Plastic Tube Scrapers (courtesy of Conco Systems, Inc.)

6-17


Figure 6-14 Metal Tube Scrapers (courtesy of Conco Systems, Inc.)

6-18


Scrapers are one of the most effective off-line tube-cleaning methods developed. Because they are strong enough to remove hard deposits, they retard under-deposit tube pitting. Properly used, scrapers will not stick inside a tube unless the tube is already damaged or obstructed. When metal scrapers are used to clean tubes in condensers, it is important to verify that the scrapers are not left in the tubes. Scrapers left in the tubes might promote subsequent tube failure by blockage erosion. Completely obstructed tubes should be plugged. 6.2.2 Mechanically Driven Systems The most difficult foulants can be removed by motor-driven scrapers. Scraper heads are available in a variety of configurations. Most are equipped with flexible shafts or universal joint shafts and are motor-driven. Some are adjustable to accommodate varying tube bores. An example of a motor-driven scraper is shown in Figure 6-15.

Figure 6-15 Mechanically Driven Brush [15]

6.2.3 Pressure-Driven Systems In water lancing, the foulant is removed by shearing the layers with high-pressure, high-velocity water jets. Water pressures of 8,000-10,000 psi (55 to 69 megapascals) are normally used and pressures as high as 18,000 psi (124 megapascal) can be used. Operators need to take extreme safety precautions. These high pressures can collapse tube ends, collapse tube inserts, damage tubesheet coatings, and damage tube-to-tubesheet joints. Water is pumped through a flexible hose or rigid metal shaft, the end of which is attached to a stainless steel head. The head is drilled with several orifices to define a particular spray pattern that will usually provide self-propulsion as well as tube wall cleaning. Lance head design is critical to foulant removal. Typical water lance heads are shown in Figure 6-16.

Figure 6-16 Typical Water Lance Heads [15]

6-19


This technique, also called hydrolancing or hydrolasing, uses a high-pressure water spray to remove fouling deposits. Water is pumped through a flexible hose or a rigid metal shaft fitted with a steel spray head at the end. The head is designed for the spray pattern to impinge on the tubes to remove scales. The water pressure also propels the head forward. The water can also be treated with chemical inhibitors to protect steel surfaces or copper alloys. Some utilities add surfactants to the water to accelerate scale removal. Because the high-pressure water can damage weakened tubes, the condenser should always be leak-tested after hydroblasting. A hydrostatic testing (filling the condenser hotwell with water) should be sufficient. 6.2.4 Waste Disposal Dry off-line processes require an industrial vacuum cleaner with a filter to collect removed deposits and limit airborne dust. Tarps or plastic wraps can also minimize airborne dust. When cleaning closed cooling water systems, wet processes might require containment, testing and disposal of debris-laden water. Temporary traps or temporary rigid plastic channel covers can contain water locally. Using detaining drums and/or temporary screens can limit the discharge of large particles into the water drain system. Passivation and deposit-removing chemicals added to the water can complicate waste disposal. Water containing chemicals might require either treatment or off-site disposal. When cleaning open cooling water systems, the debris is generally released into the outlet waterbox. The debris then flows to the discharge of the cooling water piping. 6.2.5 Advantages and Disadvantages of Off-Line Systems Off-line systems cost significantly less than on-line systems. Additionally, off-line cleaning systems require no maintenance or monitoring as compared to on-line equipment. There are no balls to replace, no back-flushes to initiate, nor any reverse-flow system transients. When the offline cleaning is completed and the unit is back in service, the cleaning components are stored and require no attention. A principal disadvantage of off-line tube cleaning equipment is that it interrupts service. The condenser cannot function at full load while it is being cleaned and reducing load can be costly, especially with forced outages. Off-line cleaning can be scheduled during refueling/boiler outages or during scheduled load reductions. On-line and off-line tube cleaning systems share the objective of maintaining tube cleanliness and ensuring intended heat transfer rates. Tube cleanliness is maintained continuously by on-line systems. Tube cleanliness might begin to deteriorate soon after an off-line tube cleaning is completed. If this situation can be tolerated because of very conservative design margins, then off-line systems can be sufficient.

6-20


To prevent this, a conscientious program of off-line tube cleaning once or twice per year at scheduled outages is good practice. Off-line systems assure every tube is cleared and cleaned. Each type of off-line cleaning device has limitations. For instance, although using bristle brushes driven by relatively safe water pressures of 200-400 psi (1.4-2.8 megapascals) is the most common off-line cleaning method, the brushes might be effective only for the softest foulant. Scrapers and high-pressure water lancing might be more effective against more tenacious deposit, but they might need help where fouling buildup has been allowed to get too thick and hard. Key Human Performance Point When high-pressure water lancing equipment must be used, it presents a potential safety hazard to operating personnel because of pressures as high as 8000-10,000 psi (55-69 megapascals). Often this equipment is used by a contractor who specializes in high-pressure equipment. Propelling the cleaning devices through the tubes with high-pressure air or air/water also presents a safety hazard due to very high travel speeds. As a final choice, rotating brushes, cutters and scraping heads are possible but they are too slow to use for routine surface condenser tube cleaning. These methods are used where serious problems exist in the tubes and other off-line methods are unsuccessful. They can easily damage tube walls if they are used incorrectly. All off-line tube cleaning methods use consumable cleaning devices that wear out and require periodic replacement. The advantages of the air/water-driven bristle brushes, rubber plugs, and plastic pigs are: x

The equipment is significantly cheaper than on-line alternatives.

x

The cleaning devices require no special maintenance or monitoring.

x

The cleaning operation is fast.

The disadvantages of the air/water-driven bristle brushes, rubber plugs, and plastic pigs are: x

The equipment must be out-of-service with lost revenues from downtime or must be scheduled during refueling/boiler outages or during scheduled load reductions.

x

There is increased labor cost to operate.

x

They might not be effective on the types of deposit present.

The advantages of using the water-driven scrapers are: x

The scraping edges are spring-loaded to match the specified tube diameter.

x

The scrapers can collect a tube deposit sample for testing.

x

The scrapers are safe and fast. 6-21


The disadvantages of using the water-driven scrapers are: x

The equipment must be fully or partially out-of-service.

x

The scrapers can damage the tube walls if used incorrectly.

x

The scrapers can become lodged in the tubes.

The advantages of using water lances are: x

Water lances use high-pressure water spray to remove scale.

The disadvantages of using water lances are: x

The equipment must be fully or partially out-of-service.

x

There is a potential hazard to operating personnel.

x

The water lances can damage the tubesheet coating.

x

The water lances can collapse thick tube walls at the tube-to-tubesheet joint.

x

Degraded tubes can be damaged and begin to leak.

6.3

Chemical Cleaning [18]

Chemical cleaning techniques can be applied to open and closed cooling water systems. Chemicals are selected based on the scale composition to be removed and the condenser materials. Typically, a removed tube and/or corrosion coupon is used in bench tests to verify solvent compatibility with the condenser materials. Pulling tubes can be used for process optimization. Visual inspections and eddy current measurements are used before and after cleaning to evaluate cleaning effectiveness. Both on-line and off-line chemical cleanings have been performed in the industry. On-line cleanings can be as simple as injection of the cleaner into a closed cooling water cycle. Off-line chemical cleaning involves the use of temporary equipment for chemical injection, condenser water recirculation and vapor removal. The type of chemical cleaning selected for a specific plant (on-line versus off-line techniques) is based on the foulant, materials, design issues, schedules, and so on. Key Technical Point Typically, on-line and off-line chemical cleaning techniques remove 3-10 mils (76 –254 µm) of deposit in 30 to 60 hours. On-line techniques are applied to one waterbox at a time or to the entire condenser. The off-line techniques apply to the entire condenser. Chemical cleaning of the condenser typically regains lost megawatts.

6-22


7 AIR/WATER IN-LEAKAGE

This section covers air in-leakage effects, detection methods, and corrections and water inleakage effects, detection methods, and corrections.

7.1

Air In-Leakage Effects [3]

For maximum thermal efficiency, corresponding to a minimum backpressure, a vacuum is maintained in the condenser. This vacuum encourages air in-leakage. To keep the concentration of non-condensable gases as low as possible, the condenser system must be leak tight, together with any part of the condensate system that is under vacuum. Failure to prevent or remove the non-condensable gases can cause serious corrosion in the system, lower heat transfer properties, and/or increase plant heat rate due to the backpressure rise associated with a high in-leakage. The Heat Exchanger Institute (HEI) standard for new condensers is to reduce oxygen levels below 7 parts per billion (ppb) at full load and maintain non-condensable in-leakage to less than 6.0 standard cubic feet per minute (scfm) (10.2 cubic meter/hr.). Achieving and maintaining these limits will depend on the maintenance performed to achieve a leak tight condenser. There is always some small residual amount of air in-leakage into the turbine/condenser system through labyrinth glands, penetrations, or other small apertures in those parts of the system that operate below atmospheric pressure. This air ingress cannot be avoided and the design value used for the condenser tube side heat transfer coefficient reflects this value. When the air inleakage rises above the threshold value, the tube side heat transfer can be affected and an increase in the condensate dissolved oxygen concentration might occur. Of course, the latter might not occur if the increased concentration of non-condensables consists of ammonia or carbon dioxide as decomposition products from feedwater treatment chemicals. The 1998 ASME Performance Test Code for Steam Surface Condensers Standard includes data regarding the maximum air loading that will allow a condenser to perform at an acceptable level. Table 7-1 indicates only the acceptable upper limit on air loading. Operation below the limit allows unaffected condenser performance. For a two condenser shell, 500 Mw unit with a total exhaust flow rate of 2,300,000 lb/hr (1,043,262 kg/hr) the upper gas load limit from the chart is 7.5 scfm (12.7 cubic meter/hr). Westinghouse proposed a residual air in-leakage of one scfm (1.7 cubic meter/hr) per 100 megawatts as being acceptable in their Operation and Maintenance Memo No. 029 in 1982. This should again be considered in terms of an upper acceptable limit that will not affect condenser performance. However, for the same 500 Mw unit referred to above, the limit would be 5 scfm (8.5 cubic meter/hr), which is lower than that recommended in the ASME Standard. These 7-1

EPRI Licensed Material Air/Water In-Leakage

criteria are clearly important when considering whether excessive air in-leakage is affecting performance. Table 7-1 Air In-Leakage Limits (reprinted by courtesy of The American Society of Mechanical Engineers) Number of Condenser Shells

Total Exhaust Steam Flow to Condenser in lb/hr (kg/hr) Between

And

Non-Condensable Gas Load Limit in scfm (meter3/hr)

One

0

100,000 (45,359)

1.0 (1.7)

One

100,000 (45,359)

250,000 (113,398)

2.0 (3.4)

One

250,000 (113,398)

500,000 (226,796)

2.5 (4.2)

One

500,000 (226,796)

1,000,000 (453,592)

3.0 (5.1)

One

1,000,000 (453,592)

2,000,000 (907,185)

3.75 (6.4)

One

2,000,000 (907,185)

3,000,000 (1,360,777)

4.5 (7.6)

One

3,000,000 (1,360,777)

4,000,000 (1,814,369)

5.0 (8.5)

Two

200,000 (90,718)

500,000 (226,796)

3.5 (5.9)

Two

500,000 (226,796)

1,000,000 (453,592)

4.0 (6.8)

Two

1,000,000 (453,592)

2,000,000 (907,185)

6.0 (10.2)

Two

2,000,000 (907,185)

4,000,000 (1,814,369)

7.5 (12.7)

Two

4,000,000 (1,814,369)

6,000,000 (2,721,554)

8.5 (14.4)

Two

6,000,000 (2,721,554)

8,000,000 (3,628,739)

10.0 (17.0)

Three

750,000 (340,194)

3,000,000 (1,360,777)

7.5 (12.7)

Three

3,000,000 (1,360,777)

6,000,000 (2,721,554)

9.0 (15.3)

Three

6,000,000 (2,721,554)

9,000,000 (4,082,331)

11.0 (18.7)

Three

9,000,000 (4,082,331)

12,000,000 (5,443,108)

13.0 (22.1)

Note that if the air leakage enters the system below the hotwell condensate level, it will have a more severe effect on dissolved oxygen concentration than if it is transported to the condenser with the exhaust steam or enters the condenser through penetrations above the hotwell level. 7.1.1 Air In-Leakage Costs [21] The primary effects of air in-leakage and some associated costs are: x

7-2

Reduction in heat transfer coefficient – The condensing tubes are usually arranged in some variation of a hexagonal pattern. The lower tubes have more air and the air does not condense. The air can inhibit the condensation of the steam by creating a low-density blanket at the tube surface. The air acts as an insulator to condensation heat transfer. This results in a reduction of the heat transfer coefficient h.


One method of calculating the heat rejection is: Q = h x A (T1-T2)

(eq. 7-1)

where, Q = Heat Rejection in Btu/hr (J/hr) h = Heat transfer coefficient A = Area, ft² (m²) T1 = Circulating water inlet temperature, ºF (ºC) T2 = Circulating water outlet temperature, ºF (ºC) In order to transfer the same amount of heat, the discharge temperature rises if h is lowered. Experiments have shown that a worst-case reduction of the heat transfer coefficient of about 30% can be expected. Typically, condensers are oversized with additional condensing surface when designed to account for excessive air in-leakage. x

Excess process steam required for steam jet air ejectors – Diligent efforts can take place to reduce the amount of condenser air in-leakage where only one steam jet air ejector is necessary. The cost associated with running two steam jet air ejectors can be approximated by calculating the amount of steam required. An equation to calculate the normal amount of steam required per ejector is: W = 144 (Pc) (Ln (Pb/Pc))

(eq.7-2)

where, P b = atmospheric pressure, 14.7 lb/in² absolute (101 kPa) Pc = condenser pressure, lb/in² absolute (kPa) Ln = natural log W = work rate, ft-lb/hr (J/hr) For example, with discharged air at atmospheric pressure and condenser pressure at 1.5 inch Hg (0.737 psia or 5.08 kPa), the work rate for saturated steam is 318 ft-lb/hr (431 J/hr). The effective volume of air at these design conditions is 606 cubic feet (17.1 cubic meter). The work required to remove one pound (454 grams) of dry air is 318 x 606 or 192,708 ft-lb/hr (261,273 J/hr or 73 watts). On a per pound basis this equals: 192,708 ft-lb/hr / 778 ft-lb/Btu = 248 Btu/hr (73 watts) per lb of air removed

(eq.7-3)

7-3


To calculate the cost saved by a reduction in air in-leakage, first calculate the energy savings then multiply by the energy cost. The energy saving is the volumetric flow rate, multiplied by the density of air multiplied by the work rate of air. (Energy/hr) = Volume/hr x density of air x work rate of air x

(eq. 7-4)

Excess electrical load when another vacuum pump is required – In plants where the air removal is obtained with mechanical vacuum pumps, it is necessary at times to use two pumps. The electrical load per pump is the horsepower of the motor converted to kilowatts (746 watts/hp), divided by the motor/pump efficiency. This factor is then multiplied by the plant capacity factor, hours in service, and the cost. Cost/yr = Energy/hr x Capacity Factor ÷ motor/pump efficiency x hours in service x cost of Power

(eq. 7-5)

For example, a 100 horsepower (74.6 kw) motor-driven vacuum pump with 80% motor/pump efficiency, 75% capacity factor, 6.5 cents/kw-hr equals a cost per year of $39,822. Loss due to backpressure deviations – The equation to calculate the losses is: Cost/yr = Heat Rate Losses x unit capacity x capacity factor x 8,760 hour/year x fuel cost

(eq. 7-6)

For example, a 100 Mw unit with 75% capacity factor, an average of 20.4 Btu/hr heat rate loss from backpressure deviation and fuel cost of $5/Mw-hr equals a cost of $20,104 per year. 7.1.2 Condensate/Feedwater Chemistry Oxygen in the condensers might be present in the incoming steam, from aerated drains, and from air in-leakage in the subatmospheric zones. In copper-alloy-tubed condensers, copper compounds can form and be pumped into the system. The copper loss in the condenser is not significant but the copper ions added to the condensate/feedwater can cause problems in other areas of the system. Both titanium and stainless steel are relatively inert and tubes manufactured from these materials do not contribute significantly to the chemistry of the system. The carbon steel condenser shell will contribute ferric oxide to the system but the contribution is usually very small during power operation. During initial startup following a plant shutdown, reaction with ferric oxide will result in higher than normal hydrazine consumption. Relatively large quantities of scale and oxides will also be released during the startup period. The consequences of excessive concentrations of dissolved oxygen (DO) in the condensate drawn from the condenser vary. This depends on whether the unit is provided with a fossil-fired boiler or nuclear steam generator. Also, it depends on whether the latter is designed as a boiling water reactor (BWR) or a pressurized water reactor (PWR). Because of the different

7-4


consequences, each type of plant has its own threshold for condensate dissolved oxygen concentration that should not be exceeded. With normal amounts of air ingress, the DO concentration should lie below the selected threshold. However, any air ingress into the condenser shell will create the potential for higher dissolved oxygen. If the source of air in-leakage lies below the condensate level in the hotwell, the increase in DO concentration can be severe. The solubility of oxygen in water also varies with temperature. The higher the condensate temperature, the lower the concentration of DO. There are numerous effects for increased DO in the feedwater system. For more information on the effects in the PWR, BWR, and Fossil systems, refer to chapter eight of EPRI report TR-112819, Condenser In-Leakage Guideline [3]. 7.1.3 Condensate Reheating The process of deaeration reverses the conditions that cause the condensate to absorb oxygen by: x

Reheating the condensate to raise it close to the saturation temperature corresponding to the vapor pressure. The higher the temperature then the lower the solubility of oxygen.

x

Providing a method for dispensing the water so that dissolved oxygen can reach a free surface and be released from the water.

x

Bringing the water to its boiling point to minimize its solubility.

x

Venting or otherwise removing the released oxygen to prevent reabsorption in the water.

Condensate reheating within the condenser is accomplished by allowing the condensate to fall through a steam blanket between the bottom of the tube bundle and the surface of the hotwell. This steam blanket is formed by exhaust steam from the turbine that is directed around the tube bundle, or in steam lanes in the tube bundle, to the lower part of the condenser. The steam is directed to the bottom of the condenser and hotwell area. In this way, a substantial amount of its velocity energy is converted to pressure energy. The local static pressure in the hotwell area and under the tube bundles might actually exceed the static pressure at the condenser inlet. The condensate falling from the tube bundle through this zone of increased static pressure can be heated to the saturation temperature and effect deaeration of the condensate. One characteristic of this static pressure in the hotwell area is that it is load-sensitive. The steam flow paths around the tube bundle and through the steam lane in the tube bundle are fixed dimensionally. They are sized for steam flows in the higher power ranges. Full reheating of the condensate is not achieved at the lower power ranges. This causes the dissolved oxygen levels to rise. Some condensers incorporate a system to admit steam into this deaeration zone in order to achieve the desired reheating and deaeration at low loads. 7.1.3.1

Condensate Steam Sparging

This method consists of providing steam nozzles just above the maximum hotwell level, fed by extraction steam from an appropriate source. The nozzles spray up toward the tube nest and are 7-5


arranged in a manner to distribute steam near the cooling water inlet region. The steam supplied by the nozzles offsets the subcooling, augments the normal steam upflow, and is regulated to ensure that the condenser pressure does not exceed the design value. The sparging system functions mostly during reduced power operation and startup. There is an approximate linear relationship between sparging steam flow requirements and average or net condensate subcooling. The condenser steam sparging flow is approximately 2% of the main steam flow when the average condensate subcooling is about 30°F (-1.1°C). Deaeration improvement by this method can be enhanced by adding distribution plates or trays that reduce the condensate water droplet size or film thickness. This facilitates the release of dissolved non-condensable gases. Such an arrangement is applying the principles used in deaerating heaters for the purpose of reducing condensate oxygen levels. More space is needed between the bottom of the tube nest and the hotwell water surface. 7.1.3.2

Hotwell Deaeration

Hotwell deaeration is an extension of the condenser deaeration process described above with the exception that the steam sparging nozzles are located below the surface of the hotwell water. This method is well known and is applicable during startup operations when heating the hotwell water and subsequent deaeration is the objective. It relies on the hydraulic motion of the bubbles to break up the water, which is already near the saturation temperature, and so release the dissolved gases. Hotwell deaeration also relies on an extended period of exposure (< 20 minutes) to the sparging steam. Nitrogen and other gases have been used on small-scale applications to perform a similar function. 7.1.3.3

Condenser Drains

The low-pressure drains are another major source of air ingress into the condenser. Air in-leakage into the vacuum regions of the turbine, the extraction system, and low-pressure heater shells becomes dissolved in the condensate drain water. Effective deaeration of the drain water depends upon the location and manner in which it is introduced into the condenser. For example, if the drain water is dumped into the lower region of the condenser shell, deaeration is likely to be inefficient or nonexistent. To ensure efficient deaeration, drain water flow should be dispersed in relatively thin films that pass through or are in contact with counterflow steam before it reaches the hotwell. One way to accomplish more efficient drain water deaeration is to introduce the drain water into the condenser above appropriate regions of the tube nest and to distribute the inflowing water over perforated plates. This method facilitates contact between the drain water and upflowing steam. Spray devices provide better conditions for deaeration than perforated plates. Specific perforated plate designs have to be provided for each condenser configuration. However, it is estimated that two 3 x 5 feet (0.9 x 1.5 m) perforated plates with 1/4-inch (6.4 mm) diameter holes in each shell provide reasonable distribution in a condenser of an 1100 Mw plant.

7-6


7.1.3.4

Makeup Water

The makeup water is another important source of oxygen ingress. In many plants, the condensate storage water is not deaerated. Because the water temperature is usually below the saturation temperature, its dissolved oxygen content is high. Where the makeup water oxygen level approaches the equilibrium value of 10 ppm for aerated water at ambient temperatures, the effect on the condensate oxygen levels is pronounced. This assumes there has been little deaeration of the makeup water as it flows into the condenser. Plant makeup water flow rates vary widely but are generally in the range of 0.1% to 1.0 % (20 to 300 gpm or 76 to 1136 liters/min) of the rated feedwater flow. Preheating of makeup water would assist in deaeration. However, in existing condensers, rearrangement of the internal spray piping might be necessary to avoid damage to the condenser. The design considerations for reducing the effect of makeup water oxygen content are similar to those for drain flows. They involve introducing the water through sprays mounted high in the shell, preferably above the tube nest, and dispersing it in a manner that will provide good contact with the steam. The high pressures available and the relatively small quantities for normal makeup requirements favor the use of spray nozzles. Such nozzles, located in the tube nest region, are used for normal makeup in a number of PWR plants. Consideration should be given to introducing the normal makeup water, via spray nozzles, above the tube nest. Delivery of normal makeup water to the hotwell should be avoided. Unless makeup water is thoroughly deaerated before or after the water enters the condenser, oxygen ingress from this source can be significant.

7.2

Air In-Leakage Detection Methods [3]

The primary sources of air in-leakage in a condenser are: x

Atmospheric relief valves or vacuum breakers

x

Rupture disks

x

Drains that pass through the condenser

x

Turbine seals

x

Turbine instrumentation lines

x

Turbine/condenser expansion joint

x

Tubesheet to shell joints

x

Air-removal suction components

x

Penetrations

x

Condenser instrumentation, sight glasses, and so on

x

Low-pressure feedwater heaters, associated piping, valves, and instruments

x

Valve stems, piping flanges, orifice flanges 7-7


x

Manways

x

Shell welds

x

Condensate pump seals

There are several methods used in finding air in-leakage to the condenser. The use of tracer gas is the most commonly used method. Another method is to use a sensor probe to measure the amount of air leaking into the condenser. Infrared technology can also be used to find areas of inleakage. 7.2.1 Tracer Gas Testing [22] Gas tracer leak detection of any sealed container requires that a pressure differential exist between the interior and exterior of the component being tested. The tracer gas is placed in the area of higher pressure and migrates through leakage paths to the lower pressure area. When testing surface condensers, the gas is systematically sprayed over the exterior of the condenser and components that are a part of the vacuum boundary. The off-gas exhaust stream is then analyzed for the presence of the tracer gas. Leak detection using a gas tracer is a widely accepted technique of identification of condenser leakage. Optimum conditions for gaseous tracer leak detection of surface condensers require that the unit be on-line at ~20% turbine loading. The technology of surface condenser leak detection is straightforward. A detector probe is installed in the non-condensable off-gas exhaust stream. A tracer gas is released in proximity of suspected condenser leak paths. Leakage is identified when the tracer gas migrates through the leak into the condenser. The tracer gas is expelled from the condenser steam space with the other non-condensables in the off-gas. A small portion of the off-gas mix is drawn into the probe and to the detection system. The system analyzes the concentration of the tracer gas and reads onto a display. A technician monitors the display and relates the results to the technician disbursing the tracer gas. Several different tracer gases including halogens (freon, sulfur hexafluoride), helium, and perfluorcarbons have been investigated. Helium is typically used and readily dissipates. Sulfur hexafluoride (SF6) is four orders of magnitude more sensitive than helium. Commercial SF6 analyzers have the capability of detecting 1 part of SF6 gas in 10 billion parts of air. SF6can be released directly into the circulating train while it is in service. Another advantage in using SF6 gas for air in-leakage testing is that a tracer gas release mechanism is available that is extremely portable, has an extended operating duration, and has a variable release concentration to allow for sensitivity adjustment. The possibility of contamination of plant components and the potential for contaminating the feedwater are minimal using the SF6 tracer gas. The low concentrations of SF6 gas necessary for detection, the low solubility of SF6 gas in water, and the high efficiency of air-removal systems on non-condensable gases reduce the probability of measurable amounts of tracer gas carrying over into the condenser.

7-8


In the plant environment, multiple leakage paths can exist in close proximity. A method must be employed to isolate a specific leak from neighboring leaks. This can be accomplished by releasing at the outer most items first, while directing the gas away from the other components. The technician monitors the incoming signal and notes when the indication returns to the background signal. The process is then repeated for the remaining components. Signal interpretation of indications for components in close proximity requires evaluation of the signal magnitude, signal response time, signal slope, and signal clear-out. See Figure 7-1 for an example indication of a leak. Signals with large magnitudes and quick response times usually indicate multiple leaks in close proximity.

Figure 7-1 Chart Recording of a Typical Leak Response [3]

The successful use of tracer gas leak detection in a power plant is an acquired skill. It can be explained, but it must be practiced to achieve competency. At its simplest level, a tracer gas is released during the leak search and a signal is displayed when the gas is detected. There are techniques in the gas release and signal interpretation that require experience and careful attention to detail. In a laboratory setting, it is possible to test and segregate one component at a time. A leak or noleak determination can be made from the presence or absence of a signal. In the plant environment, multiple leakage paths can exist in close proximity. This requires that a method be used to isolate a specific leak from neighboring leaks. Also, the user must recognize signals caused by the gas cross-over that occur while testing components near the leak.

7-9


For example, there is an air leak on a turbine shaft, gland seal assembly. This is the most frequent type of leak experienced on a steam turbine unit. From Figure 7-2, the possible leakage locations include the: A.

Turbine shaft and labyrinth seal

B.

Seal housing joints between the upper and lower cases on both sides of the housing

C.

Mating joint between the seal assembly and the turbine hood circumference

D.

Joints between the upper and lower turbine casings

E.

Two points at which B, C, and D intersect

F.

Jacking bolt holes on the turbine upper to lower case joints

Figure 7-2 Turbine Shaft Gland Seal Housing [3]

In a typical air in-leakage test, tracer gas is released in the gland seal housing area in a sixsecond burst to determine if any of the paths are leaking. If the tracer gas is detected, the process of differentiating between leakage paths (isolating) begins. Three things enable the identification of a specific leak: x

An attempt is made to direct the release of the gas in such a way that only one item is shot at a time. This is done by releasing gas at the outermost items first and directing the gas away from the other components. In this example, either side of the turbine case joint is a shot. Care must be taken to direct the gas release out and away from the shaft seal assembly. A quick burst, three seconds or less, is all that is required. With the release, a verbal On

7-10


message is relayed simultaneously to the detector operator. This is followed by the name of the item or component being shot. x

The time between gas release and the signal response (response time) is noted by the detector operator. When hearing the On message, the technician taps the event marker switch on the strip chart recorder. This measures the elapsed time between the message and the first sign of a signal response.

x

Signal characteristics such as peak magnitude, rate of rise of the signal (slope), elapsed time for the signal clear-out, and peak width are all significant. The operator observes the incoming signal and records the peak value (magnitude) of the indication, together with the name of the item shot, paying attention to the slope traced by the signal rise. Upon clear-out of the gas, the signal indication returns to background. This process is repeated for the remaining components.

7.2.1.1

Tracer Gas Equipment

The equipment required for condenser tracer gas leak detection, for both helium and sulfur hexafluoride, includes: x

Gas injection equipment

x

Gas sampling equipment

x

Gas analyzer

The analyzer is comprised of panel-mounted flow meters, potentiometers, valves, and a digital readout device that provides the controls necessary to establish sampling conditions and to indicate the presence of SF6 in the sampled off-gas (Figure 7-3).

Figure 7-3 Gas Analyzer [3]

The release package provides a convenient means of releasing SF6 in the concentration necessary for air in-leakage testing, as well as test shots for both air and tube leakage tests. Because of the sensitivity of this technique, it is not necessary or desirable to use pure (100%) SF6. The commercially available device is a hand-held battery-powered unit that meters a precise amount of pure SF6 into a dilution stream of ambient air (see Figure 7-4). It operates on a rechargeable 7-11


internal battery pack with sufficient capacity to power the unit for the duration of an entire air in-leakage inspection. A refillable aluminum reservoir bottle contains the SF6 and holds enough gas for many tests. The device is equipped with a pressure switch that interrupts operating power if gas pressure falls below the required level. Thus, when the contents of the vessel have been expended, this switch prevents the possibility of testing with dilution air only.

Figure 7-4 Tracer Gas Release Device [3]

The concentration of the discharge mixture, nominally 1,000 ppm, can be controlled by adjusting the delivery pressure on the regulator. The ability to vary the discharge concentration allows the operator to decrease the concentration if background levels begin to rise. However, if the background level remains steadily low, the SF6 concentration can be increased for difficult areas such as leakage below the condenser hotwell water line. A three-section telescoping aluminum probe allows the tracer mixture to be directed accurately over the suspected leakage areas. It also enables the operator to reach areas that are difficult to access. Two switches control the release of the tracer. One controls the dilution air fan and the second opens the solenoid-controlled valve, discharging the pure SF6 into the dilution stream. The purpose of the sampling equipment, shown in Figure 7-5, is to draw a representative sample from the condenser air-removal system, to cool and dry it, and then to transport it to the analyzer.

7-12


Figure 7-5 Schematic Diagram of SF6 Sampling System [3]

Because moisture will significantly affect the operation of the analyzer, complete removal of moisture from the sample gas is desirable. When using a pump to draw an off-gas sample from the air-removal system, it is important to confirm that air is not leaking into the sampling system on the vacuum side of the pump. Air leaking into the system will reduce the concentration of the tracer gas in the off-gas, therefore reducing the overall sensitivity and effectiveness of the test. Prior to beginning component testing, the sampling system itself should be tested for leakage by releasing diluted tracer on those connections between the sampling system components that lie upstream of the sampling pump.

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7.2.1.2

Data Interpretation

Signal interpretation of indications for components in close proximity requires that consideration be given to the following prioritized items: x

Signal magnitude

x

Signal response time

x

Rising slope of the signal response

x

Clearing time of the signal response

x

Interpretation of the data should proceed as follows:

1. After shots have been made and recorded for each of the possible paths, one indication might stand out above the others. If one of the signals has a magnitude that is substantially greater than any of the others, it is probably the leak being sought. 2. When two adjacent test areas show peaks of equal or near-equal magnitude, the one with the shorter response time is usually associated with the leak location. 3. Steepness of slope relates to how quickly the gas is drawn into the leak. If magnitudes and response times of two or more shots are equal, a steeper slope of rise (that is, a shorter elapsed time between the onset of the signal and the signal peak) will indicate which shot is the leak or the more significant leak if several leaks exist. 4. Alternatively, if differences are still indiscernible, observing the clear-out times (elapsed time from the signal peak to a return to background) for each indication can be helpful. For indications of equal magnitude, a faster clear-out would imply the shot location is closer to the leak. Although application of these last two tests might sound difficult, they can be performed quite easily. The strip chart can be displayed in such a way that all of the signals for the assembly can be seen and, if magnitudes and responses are equal, the signal with the narrowest peak-width (signal start to signal finish) tends to represent the actual leak. 5. Determination is made whether there is more than one leak on the assembly. Signals, from tests associated with non-adjacent items, both having large magnitudes and quick response times, indicate that there are multiple leaks. 7.2.1.3

Tracer Gas Selection

The selection of tracer gas depends on many utility-specific factors including test equipment on hand, training of the staff, plant conditions, and time available. Based on their experience, one contractor in the industry has created the following guideline to determine which tracer gas to use:

7-14


x

Unit air in-leakage — If the unit has greater than 10 scfm (17 m3/hr) of air in-leakage, either helium or SF6 can be used as the tracer gas. If the unit has less than 10 scfm (17 m3/hr), then the use of SF6 is recommended for its greater sensitivity (one part SF6 per billion parts of analyzed gas) as compared to helium (one part per million above helium background of ~5 ppm).

x

Dissolved oxygen — Due to its negligible solubility in water, it is recommended that SF6 be used as the tracer gas to search for the cause of DO leakage below the steam space. This does not preclude using helium when SF6 is not available.

x

Unit turbine power — If the unit has 20% or greater turbine power, either tracer gas can be used. If the unit has no power, it is recommended that helium be used due to its lower sensitivity than SF6. This does not preclude the use of SF6 but, when used, care should be taken to ensure that the SF6 dilution rate is increased to bring the sensitivity levels down to that of helium.

x

Unit size — All units can be inspected with either helium or SF6 as the tracer gas.

7.2.1.4

Testing Areas [22]

A plant-specific checklist of the components requiring testing for air in-leakage should be developed. The checklist should start with a walkdown of the unit. Flow diagrams should be reviewed for inspection boundaries. Operating personnel should be consulted to confirm vacuum-boundary locations. The walkdown should start on the turbine deck and proceed to each floor elevation below the turbine deck. Key Human Performance Point The unit air in-leakage survey should start on the turbine deck at one end of the unit, continue around the turbines, include any other components on the deck applicable to the test, and then proceed in a similar manner with the next deck down. Regardless of the type of gas used for testing, the test should be performed from the top of the unit to the bottom of the unit, one floor at a time. By performing the test first on the upper elevations, the tracer gas drifting to unknown leak locations is reduced. Heat convection in combination with normal building ventilation flows usually results in large, upward air mass flows. The narrow spaces between most condensers and their supporting walls tend to act as a chimney, sweeping air towards the condenser and then up to higher elevations. For this reason, testing on the floor below the turbine floor should begin on those components closest to and highest up on the condenser unit. For example on the mezzanine floor, the gas releases should begin on one end of the unit by the expansion joint and progress down the slope of the condenser neck, testing the various penetrations. After this area is complete, testing can proceed outward from that end of the condenser to testing penetrations on feedwater heaters, and so on. By adhering to this order of testing, confusion is avoided when gas released at components out and away from the condenser is swept toward the condenser and drawn into leaks on the shell.

7-15


After all components at one end of the condenser have been tested, the technician can move around to another side of the condenser and continue testing. With the sensitivity of detectors available, large leaks of 10 scfm (17 m3/hr) will begin to give indications while testing other components many feet away from the actual site of the leak. Every shot made in the area will show some response. Decreasing response times and increasing magnitudes of the section signal will indicate the direction of the leak. The presence of a large leak might override or mask the signal of smaller leaks in the area, requiring a repair before leak searching can continue in the area. In order to isolate a leak, it is important for the technician to know what has been tested. This is why it is important to keep a log of everything that is sprayed with the tracer gas. If a large leak is found on the manway on the west side of the turbine, an indication of this must be made on the strip chart recorder. Technicians can waste a lot of inspection time searching for a leak that they have already found. This can be avoided by ensuring that the response time compares favorably with the typical response time originally recorded during the test shot. Following these suggestions and performing an orderly, systematic, and detailed search pattern will greatly assist leak detection personnel in the successful application of the gaseous leak detection technique. To attempt to quantify every leak might not be cost-effective. However, there are various methods to determine the relative size of existing leakage paths. SF6 and helium analyzers give readouts, one in millivolts, the other in divisions. Plant personnel can determine a plan of action to repair the leaks by comparing either the millivolt readout or the division readout. 7.2.1.5

Air In-Leakage Checklist [3]

A plant-specific checklist of the components requiring inspection during an air in-leakage test should be included in the test procedure. This section details the method for compiling a checklist. A well-constructed air in-leakage checklist will: x

Ensure that all components that might contribute to condenser air in-leakage are inspected during the test

x

Facilitate testing by detailing the equipment in the order in which the testing will be performed

x

Include simplified equipment drawings that will aid in recording the leak locations

To create an initial draft of the checklist, an operator familiar with the on-line operation of the unit and a test technician should perform a review of the drawings and flow diagrams to establish the inspection boundaries. This then serves as the basis for a walkdown of the unit, during which the systems and components that require testing for leaks are itemized.

7-16


This walkdown inspection should start at one end of the turbine deck, continue around the turbine unit, and then proceed in a similar manner for each elevation, thus simulating the proposed testing order. By referring to the piping installation diagrams and the equipment operating procedures, the operator will be able to define the vacuum boundary locations for the components. These will be the points at which the testing will stop for that elevation. The vacuum boundaries for each component should be marked on the system piping installation diagrams for later reference. As a minimum, the checklist walkdown draft should contain information on all items in the following outline, assuming that the equipment in the following list is present on the unit in question. When in doubt as to whether a particular item lies within the vacuum boundary, it is recommended that the item be tested with the tracer gas. I.

Turbine Deck

A.

Low-pressure turbines 1. Gland seals and housing flanges 2. Turbine case flanges 3. Rupture disks 4. Manways 5. Steam cross-over lines a. Expansion joints b. Turbine penetrations 6. Turbine penetrations under the turbine skirt a. Hood spray penetrations b. Sensor penetrations c. Miscellaneous valves, lines, and so on Moisture separator reheaters 1. Vent and drain lines routed to the condenser Reactor/Boiler feed pumps (if installed on turbine deck) 1. Motor or main turbine driven a. Shaft seals (if seal water system returns to condenser) 2. Steam turbine driven a. Gland seals and housing flanges 1. Inboard seal 2. Outboard seal b. Turbine case flanges c. Rupture disks d. Steam stop valve drains and case penetrations e. Exhaust duct isolation valve f. Exhaust duct expansion joints

B. C.

II.

Mezzanine Level

Most turbine/condenser units are constructed in either a three- or four-deck configuration. For the purpose of this equipment outline, a three-deck configuration was assumed. A. B.

Turbine to condenser expansion joints Steam bypass lines and penetrations 7-17


C.

D.

Air-removal lines 1. Line penetrations 2. Isolation valves 3. Condenser vacuum breakers Feedwater heaters 1. Condenser neck mounted a. Penetration expansion joints 2. Floor mounted a. Extraction steam lines 1. Stainless steel expansion joints 2. Weld joints b. Heater shell penetrations c. Relief valves d. Drains

Items listed are with regard to low-pressure heaters, but the vacuum boundaries for all feedwater heaters will vary with the turbine power loading. Thus, the vacuum boundaries for several load conditions (start-up, low power, and full load) should also be recorded. E. F. G. H. I.

Condenser manways and penetrations Upper sections of condenser waterbox tubesheet flanges Main steam stop-valve drains 1. Before seat drains 2. After seat drains Heater drain tanks (Flash tanks) 1. All penetrations and lines Seal steam condensers 1. Loop seals and loop seal drains

III.

Grade Level (Basement)

A.

Condenser penetrations (the penetration weld proper and along the line away from the condenser to where vacuum conditions no longer exist) 1. Steam dumps 2. Condensate makeup lines 3. Drain headers Waterbox tube sheet flanges Hotwell penetrations 1. Sightglasses 2. Level transmitters 3. Condensate lines Condenser supports Heater drain pumps Condensate pumps 1. Pump suction strainer housing a. Pump suction strainer housing drain 2. Pump expansion joint

B. C.

D. E. F.

7-18


3. 4. 5. 6.

Pump inlet flange Pump floor-mount flange Pump shaft seal Pump-housing penetrations

If air-removal lines are installed on the pump housing or pump case, the valves on these lines should be opened during the test. G.

Air-removal equipment 1. Steam jet air ejectors a. Flange and threaded connections b. Inter-condenser penetrations c. Condensate drain seal d. Isolation valves e. Drains 2. Mechanical vacuum pumps a. Flanged and threaded connections b. Shaft seals c. Air jets d. Isolation valves e. Cylinder head (piston-type)

Many air-removal configurations incorporate air-assisted jets to accelerate the off-gas flow to the vacuum pumps. These jets pull in large volumes of ambient air, which is funneled into the offgas stream. These jets must be valved out when performing the leak test because the large volume of the assisting air ~100 scfm (170 cubic meters/hr) dilutes the tracer gas concentration in the off-gas. A drawing should be made for each low-pressure turbine and for each exposed condenser section. Penetration numbering should follow the sequence of the testing order. Details such as the Plant North orientation and penetration numbers cross-referenced to piping installation diagrams should be included. Figure 7-6 is an example of a drawing.

7-19


Figure 7-6 Condenser Penetration Map [3]

It is not recommended that complete installation diagrams be included in the checklist. Due to their large size and complexity, they do not readily facilitate testing. Instead, the relevant drawings should be extracted from the larger diagrams and reduced to a size convenient for inclusion in the checklist document. The draft checklist should then be rewritten into a format that allows recording of the information gathered during the air in-leakage test. Finally, the completed checklist should be reviewed to verify that it details the required equipment checks in the order in which the test will be performed.

7-20


7.2.1.6

Off-Line Testing [3]

This section details a testing method that can be used when the condenser air in-leakage rates are so excessive that the unit cannot be maintained on-line. The process of condensing steam creates a partial vacuum in the condenser. Non-condensables are removed by pumps. Typically, the inlets for these pumps are located near the air-removal section of the tubesheet, close to the bottom of the condenser and just above the hotwell. The downward flow of steam from the turbine exhaust propels the non-condensables toward the airremoval inlet, concentrating them in this area until they can be removed. When the unit is off-line, the absence of this steam flow allows non-condensables to spread to all areas of the condenser. Movement of the flow of this air mass is only a gradual migration from the in-leakage points to the air-removal inlet. Additionally, the air-removal equipment will be operating at reduced efficiency because the air is no longer being concentrated at the inlet. For these reasons, attempts to perform condenser air in-leakage testing with the unit off-line generally meet with failure. With no steam to hasten the removal of the tracer gas, the signal response time will be slow, the signal will take several minutes to peak, and it will require many more minutes to clear out. Performance of an air in-leakage test with steam in a bypass mode will not provide satisfactory results. Typically, bypass steam dumps into one side of a condenser section at an elevation lower than the uppermost condenser tubes. Steam entering at such a location does not provide the same “condenser sweeping” action that the turbine exhaust does. The only instance in which off-line gaseous tracer air in-leakage testing should be attempted is when high in-leakage rates prevent the unit from being brought on-line. Depending on the size of the condenser and the installed air-removal equipment, this would be an in-leakage rate of 80 scfm (136 m3/hr) or more. Two differences from the normal test conditions would make this test feasible: x

The large volume of air leaking into the condenser creates an acceptable flow of noncondensables to the air-removal area within the condenser.

x

The test goal is reduced to just locating the large leak or leaks that are preventing the unit from being brought on-line. Once found and corrected, the unit is put on-line and normal testing can continue.

The test equipment setup for off-line testing is the same as for on-line testing. In addition to the test equipment, the condenser vacuum pump and gland seal steam systems must be in operation. The absence of seal steam to the shaft glands can cause condenser air in-leakage rates to increase by hundreds of cubic feet (cubic meters) per minute. Small condenser leaks might not show any indication due to the dilution caused by the great volume of air entering the condenser through the large leak. However, when the tracer gas is released in proximity to the large leak, more of the tracer gas will be drawn into the condenser, thereby helping to offset the dilution.

7-21


When the leak indication is identified, the leak isolation process continues in the manner of the on-line test by releasing the gas in smaller search areas until the leak is isolated. 7.2.2 Multisensor Probe Another tool for locating the source of in-leakage is the multisensor probe (MSP) instrument shown in Figure 7-7.

Figure 7-7 Multisensor Probe [3]

7-22


This instrument, with its sensor located in the exhauster vacuum line, has the ability to measure the precise amount of air in-leakage entering the condenser. At the same time, the instrument also measures the exhauster capacity. This indicates whether it is responsible for the excess backpressure. With a sensor in each air-removal line leaving the condenser, the search field for using the tracer gas can be reduced to the number of lines monitored. Any leak into a condenser section will be largely removed by its air-removal section. Leaks can be measured with this instrument below the level that affects the condenser backpressure. For example, air in-leakage could be maintained at between 1/3 and 3/4 the exhauster capacity. This in-leakage instrument provides high-resolution in-leak detection to 0.1 scfm (47 cm3/sec), with 0.5 scfm (236 cm3/sec) discernible from normal background noise. The instrument can be used to monitor air in-leakage while applying temporary fixes to suspect areas. The response time is 30 seconds to 3 minutes after application of a fix to a leak area. Some common fixes include the application of duct tape, plastic wrap, and putty. A benefit of this method is that the precise magnitude of the leak is determined by the instrument. 7.2.3 Infrared Technology [21] Another method of detecting air and water in-leakage to the condenser is by using Infrared Technology (IRT). Air in-leakage, as seen through the infrared camera, appears as a cool area surrounding a void. The void can be found through the convective effects on the surface surrounding the opening when the surface of the component being viewed has a differential temperature from the ambient. If the component surface and ambient temperatures are similar, the area will go undetected using IRT. One of the characteristics of a vacuum leak is that the amount of air being drawn through the opening will change as the internal processes change. As the condenser water level fluctuates, so will the amount of air infiltration. The strengths of using IRT for condenser air in-leakage detection are: x

The method works well for examining large components such as manways, flanges, expansion joints, shaft seals, valve stem packing, and gaskets.

x

The method works well for examining hot areas such as steam jet air ejectors, low-pressure turbine gland seals, turbine expansion joints, traps, and steam piping.

x

The method works well for areas that are not easily accessible with either the helium or sulfur hexafluoride (SF6) methods.

x

The method can be used to confirm leaks found with standard methods.

x

No outside support is required from other departments as this is a non-intrusive inspection method.

x

Some of the identified leaks with this method can be verified by the temperature changes of the void from the system process changes.

The weaknesses of using IRT for condenser air in-leakage detection are: x

This method is difficult to apply to ambient temperature components.

x

Speed of inspection can be relatively slow for small components. 7-23


x

The physical location of some plant equipment makes detection difficult.

x

Some of the identified leaks require additional leak verification methods.

7.3

Correcting Air In-Leakage [23]

When the source of an air in-leakage has been located, it should be corrected. Good judgment has to be exercised when determining how to conduct the repair and how permanent to make it at that time. Much will depend on the severity of the leak. If the leak can be reduced to an acceptable level without taking the unit out of service, this might be more important than providing a more permanent solution immediately. Methods for correcting the air in-leakage will depend on the nature and location of the leak. These methods fall into four major categories: x

Piping repair or replacement — Good pipe-fitting practice will determine how to repair or replace piping or pipe fittings where air is leaking into areas of the condenser and turbine system that operate under sub-atmospheric pressures. In the case of leaks detected in any piping that lies within the waterbox, the pipes should be corrected or replaced before the unit is brought back on-line. Leaks found in those pipes that have easy external access can be corrected or replaced in accordance with good practice. Often these pipes can be repaired with the unit remaining in operation. Good pipe-fitting practice also applies when correcting penetrations where air is leaking. Many of these incorporate pipe fittings close to the penetration or else leaks can develop in welds around the penetration. These can often be corrected while the unit remains in operation.

x

Sealants — Many commercial sealants are available to the utility industry for correcting sources of air in-leakage. The selection depends on how they have to be applied, their viscosity during application, and the temperature conditions in which they have to operate. It is important that materials retain their flexibility at ambient temperatures and that they do not harden and become brittle when their temperature is raised. The use of sealants made from silicone-based materials is preferred. Many of the areas in a condenser that are prone to air in-leakage operate at belowatmospheric pressure. Sealants applied at the surface tend to be drawn into the opening or crevice, as long as the viscosity remains low. Such sealants can be applied successfully to the exposed interfaces between stationary components such as pipe or valve flanges.

x

Component repair and/or replacement — Good engineering practice will determine how leaks in condenser or turbine components should be repaired. With small cracks, the use of sealants might be considered. Welding or brazing of the component might also be a possibility and can often be performed while the unit is still on-line. It has been found that some turbine labyrinth seals appear to be tight when tested with the unit shut down. However, they seem to leak when the unit is on-line and returns to normal temperature conditions. It is possible that the internal surfaces of the seals might have become worn and the radial clearance is excessive. It might be necessary to repair or replace

7-24


the seals at the next outage. Sometimes the packing casing is distorted and needs to be welded and machined to return to the original shape. x

Packing adjustment — Leaking packings on valves or the seals on rotating shafts of small equipment can often be replaced without shutting the unit down. This is true if redundant backup equipment can be brought into operation. This allows the faulty equipment to be taken out of service temporarily for repair without affecting the operation of the unit. Adjusting the packing or gaskets between more major components is difficult to perform online. The application of a sealant at the interface can sometimes provide the solution. The replacement of packings or gaskets between machined surfaces usually requires that the bolts be removed before the packing can be replaced. This normally involves the unit being taken out of service.

7.4

Water In-Leakage Effects [3]

With the condensing steam typically generating a vacuum of 1.0 to 4.5 in. HgA (2.5 to 11.4 cm HgA), any leakage present will travel from the cooling water (tube) side to the condensing steam (shell) side. Although the condensing steam (condensate) must be kept extremely pure, the cooling water chemistry is usually maintained at higher levels of impurities. This is the result of using raw water drawn from lakes or rivers or cycled through cooling towers. This water can contain chemicals added to control biological fouling, scale and/or silt. When condensate contamination occurs, the amount depends on the chemistry of the cooling water and the size of the leak. Circulating water in-leakage into the condenser has been the major source of impurities introduced into the condensate and a major factor in corrosion. There are a number of possible causes of water in-leakage, including: x

Improperly rolled tube joints

x

Poor condenser design leading to tube failures caused by steam impingement or from damage by other components loosened by steam impingement

x

Improperly supported tubes, which can lead to tube vibration failures

x

Tube manufacturing defects

x

Galvanic incompatibility of materials

x

Underdeposit pitting corrosion

x

Tube leaks caused by corrosion

The condenser tubes and tubesheets act as barriers between the relatively impure cooling water and the high-grade condensate. Due to the vacuum inside the condenser, any tube leakage will cause contamination of the condensate by the cooling water. This can lead to increased corrosion of the secondary system.

7-25


Key Technical Point Prevention of cooling water in-leakage is important in all cooling water systems. It becomes critical when brackish water or seawater is used for cooling. A leakage on the order of 0.1 gallons per minute (gpm) (23 liters/hr) might be unacceptable and can cause significant corrosion. 7.4.1 Condensate Chemistry Detection [3] Circulating water leakage into the shell side of the condenser can become extremely serious because it allows corrosives and other undesirable dissolved solids to gain entry into the condensate hotwell. Condensate polishing demineralizers, if available, deplete rapidly and are not a long-term solution to the problem. Left unchecked, leaks will eventually cause serious damage to the piping, steam generators (or boilers), and turbines. Required response times for such leakage events are generally short and governed by the chemical composition of the circulating water and the size and number of leaks. On-line leak detection and/or chemistry indications can determine the tube bundle that contains the leak(s). The tube bundle is then isolated and the leaking tubes can be identified and plugged. If the leak(s) cannot be located, a full, forced outage might be required. The effect of condenser in-leakage on condensate, feedwater, and steam generator (boiler) chemistry can range from subtle to dramatic, depending on the size of the leak(s) and the chemistry of the circulating water. Each plant must plan its own chemistry response to a condenser in-leakage event. For example, plants using seawater as their source for circulating water see very large chemistry changes in the condensate for very small leaks. This is because of the large amount of total dissolved solids in seawater. Plants operating with a relatively pure freshwater lake as their source for cooling water might see only minor changes in the condensate during even large condenser in-leakage events. If such plants have recirculating steam generators, they might see chemistry changes in the steam generator blowdown before it can be detected in the condensate because of the concentration factor within the steam generator. Generating units that maintain close to pure water chemistry (for example, BWRs) and have an on-line conductivity that is near theoretical (0.054 Pmhos/cm), often use specific conductivity as an indicator of condenser water in-leakage. Key Human Performance Point Most plants use continuous monitoring of cation conductivity in the condensate, feedwater, and/or steam generator blowdown as the primary indication of the presence of condenser in-leakage. Cation conductivity is easily measured and can be monitored on-line by a fairly simple and rugged apparatus. Normally a sampling tray is provided under each tube bundle. The condensate in this tray is continuously monitored for conductivity. If the conductivity exceeds a certain limit, an alarm is received, indicating a possible tube leak.

7-26


Sodium is the principal cation present in most cooling waters and sodium monitoring is often used to detect condenser in-leakage. This is usually as a backup to conductivity monitoring. Sodium is also highly corrosive to power plant equipment and sodium limits are found in the water chemistry of most power plant systems. Most plants have on-line sodium monitors installed. On-line sodium monitors are more expensive and require more attention than on-line cation conductivity monitors. On-line sodium monitors are designed to continuously monitor trace levels of sodium in relatively pure waters. Typical on-line sodium monitors measure sodium content from 0.1 to 1000 ppb, but higher or lower ranges are possible, particularly in microprocessor-controlled instruments. Grab samples for chlorides in the condensate, feedwater, and/or steam generators are typically used to provide confirmation of the leak presence. Also, the presence of chlorides in combination with other analyte species can be used to determine the origin of the leak. On-line chloride monitors are installed in some power plants (usually those cooled with seawater or brackish water). On-line chloride monitors can be used to monitor condenser in-leakage. Online chloride monitors are more expensive than sodium monitors and require more attention than on-line conductivity monitors. Other chemical species, such as sulfate and silica, can be used to establish cation-anion ratios to confirm the source of in-leakage. It typically takes longer to complete their analysis than those methods used to determine the analysis of the other species discussed earlier. Also, grab samples must be used for the analysis because plants might not have on-line analyzers set up to monitor silica and sulfate in the condensate, feedwater, and steam generators. Condenser in-leakage can result in challenges to chemistry limits established to protect plant systems. These limits have been developed in plant, type-specific chemistry guideline documents and are further refined by site-specific chemistry program limits. On-line monitors on the condensate, feedwater, and/or steam generator (boiler) blowdown will give the first indication of a leak. The leak can then be confirmed with grab samples. An estimate of the leak rate can be made using the following formula: LRCT = (FRFW) (C1)/C2)

(eq. 7-7)

where, LRCT FRFW C1 C2

= Condenser tube leak rate = Feedwater flow rate = Concentration of the chemical of interest in the condensate = Concentration of the chemical of interest in the cooling water

Depending on the design of the condenser, a hotwell sample might be used to identify the tube bundle containing the circulating water leak. If the leak is too small to be detected in the hotwell sampling, lowering the power level will concentrate impurities by decreasing steam/condensate 7-27


flow while the in-leakage remains constant. This can bring impurities within analytical detection limits. When the leaking bundle has been identified, its cooling water supply can then be isolated and the bundle drained. This procedure accomplishes two things: x

It significantly speeds up the identification of specific leaks by immediately eliminating any testing of bundles that are producing high quality condensate.

x

It shows which bundles can be safely operated so that only a load reduction will be necessary and not a forced outage. This assumes that the condenser design permits waterbox isolation operation.

Power should be reduced to the point where steam flow over those tube bundles left in service does not exceed the normal full power flow rate with all bundles in service. After ventilation flow in the waterbox is established, and staging and work platforms have been placed in the waterbox, several methods of cooling water leak location can be utilized. Isolating tube bundles sequentially is an alternative to hotwell segregation. When the leaking tube bundle is isolated, hotwell cation conductivity will change. If leaks exist in more than one bundle, however, this method might not work. Unfortunately, if the condenser leak is large enough or is allowed to exist for too long a period of time, plant chemistry limits in the condensate, feedwater, and/or steam generator (boiler) might be challenged. A forced outage to prevent damage to plant equipment can be the result. 7.4.2 Water Leakage in PWRs [3] The industry has found that a tight condenser is essential to satisfactory steam generator and feedwater heater chemistry. Cooling water in-leakage through the main condenser is a major concern. This cooling water might be raw lake water, brackish water, seawater, or chemically treated cooling tower water. Water in-leakage allows contaminants to enter the condensate and cause corrosion in many parts of the feedwater, steam generator, and turbine systems. General corrosion, pitting, stress corrosion, corrosion fatigue, and their combinations are the major corrosion mechanisms resulting from the concentration of corrosive substances in the turbine. While general corrosion causes little problem, failure of turbine parts resulting from pitting, stress corrosion, and corrosion fatigue often result in catastrophic failures and long costly outages. They have been characterized as low-frequency, high-impact failures. Corrosive substances identified as problem-causing include: x

Sodium chloride

x

Sodium hydroxide

x

Sodium chloride with sodium sulfate

x

Hydrogen sulfide

7-28


x

Hypochloric acid

x

Sulfuric acid

Chemistry indications of condenser in-leakage include the following: x

Rapid increases in cation conductivity, concentrations of chlorides, sodium, and/or silica.

x

PH might drop due to dilution or the reaction with an acid found in the water.

x

With cooling towers, in-leakage is much more severe due to the chemicals added and the tendency for them to become concentrated.

Contaminants can enter the secondary system through leaks in the condenser itself, which can develop in the joints between tube and tubesheet or through-wall penetrations. Contaminants can also enter from the condensate polishers. This tends to imitate a condenser tube leak. Resin or resin fines can also leak through the tubes and enter the system. Key Human Performance Point Water chemistry guidelines for PWR once-through and recirculating steam generators can be found in EPRI TR-102134-R5, PWR Secondary Water Chemistry Guidelines, May 2000. 7.4.3 Water Leakage in BWRs [3] Water in-leakage will increase the specific activity of ionic species (chloride, sulfate, silica, sodium) in the hotwell/condensate system. The amount of leakage that can be tolerated by a specific plant is based on the removal capabilities of condensate purification equipment. For example, a plant with deep-bed demineralizers can tolerate higher leak rates or leakage for a longer period of time than plants with pressure pre-coated filters/demineralizers. Although it is desirable to maintain the hotwell as clean as possible, the economics of fixing in-leakage must be analyzed so that the appropriate opportunity to identify and correct the leakage can be selected. Items that should be considered in the decision-making process include but are not limited to: x

Resin costs due to the leaks

x

Expected dose costs for identification and repair at full or reduced power

x

Load drop requirements to drain loops

x

Cost of replacement power

x

Cost of de-optimized core management

x

Date of next scheduled load reduction

When analyzing the above cost considerations, the long-term effects on the material of the construction of the BWR need to be analyzed to ensure that maximum material longevity can be maintained. 7-29


Key Human Performance Point Water chemistry guidelines for BWR units can be found in EPRI TR-103515-R2, BWR Water Chemistry Guidelines, February 2000.

7.5

Water In-Leakage Detection Methods [3]

In the past, condenser tube leakage inspections made use of shaving cream, plastic wrap, and cigarette smoke in attempting to find the leaking tube. Some individuals believed that they could find a tube leak by placing an ear on the tubesheet. Unfortunately, out of the millions of tubes that have been inspected, very few tubes have been heard to be leaking. Meanwhile, others believed that they could locate a leaking tube by simple observation. All of the above intuitive techniques have their shortcomings so far as reliability, accuracy, and cost-effectiveness are concerned. None of these techniques offers a means of verifying, prior to putting the condenser back on-line and then checking the chemistry, that the suspected tube was the one actually leaking. These techniques are not supported scientifically and they all rely on the intuitive sense of the technician. Most leak-detection methods involve draining the waterbox that is to be inspected with the shell side of the condenser still under vacuum. With only one waterbox out of service, it is possible to perform a leak test under partial load. However, it is difficult to perform in-leakage testing with the unit shut down completely. The air-removal vacuum system might be able to lower condenser backpressure sufficiently when working alone. A major problem with all of these traditional methods is their uncertainty. To ensure that the leak has been sealed, the tube identified as leaking has to be plugged. A number of the surrounding tubes also have to be plugged. Key Human Performance Point Even when the leaking tube has been positively identified, insurance plugging can be considered good maintenance practice. In many cases, the exact mechanism that caused the tube to fail is uncertain. Selecting surrounding tubes to be plugged is insurance against additional leaks developing before the next outage. Those tubes with insurance plugs can then be subjected to eddy current testing during the next outage so that as many tubes as possible can be returned to service.

7-30


Key Human Performance Point Once the leaking bundle has been identified, a number of methods are available to determine exactly which tubes or joints are leaking. All of the methods commonly used involve testing areas of the tubesheet sequentially until the area of the leak(s) is evident. Testing then progresses to smaller areas until the exact leak location is found. The most commonly utilized leak location methods are tracer gas, plastic film, soap film NDE, smoke, water fill, rubber stoppers, pressure vacuum, and hydrostatic testing. 7.5.1 Tracer Gas Method [3] Helium/Sulfur Hexafluoride Tracer Bottled helium gas, normally at a discharge pressure of 50 psig (3.5 kg/cm2), is discharged in a burst through a hose to plenum hood. The hood is held over a section of the tubesheet. A blower or eductor must be in operation in the waterbox on the opposite end of the condenser from the test area. This is necessary to ensure that the helium gas will be drawn through the entire length of each tube tested. A helium probe sniffer connected to a spectrophotometer is attached to the discharge of the air ejectors or vacuum pumps. If a leak is present, the helium gas will appear on the steam side of the condenser and be transported by steam to the air-removal units. It is necessary for the unit to be at a minimum of approximately 20% of its full power rating to ensure sufficient quantities of motive stream. Helium does not diffuse readily and will tend to remain in an area unless a transport medium is present. Normal practice is to test 50-100 tubes in an area. Once a leaking area is located, smaller numbers of tubes/joints or each tube/joint in the leaking area are tested to identify the exact leaking tube/joint. When testing individual tubes/joints, all tubes surrounding the test subject must be plugged. Leaks as small as 1 gallon per day (3.8 liter/day) can be detected with this method. Sulfur hexafluoride gas can be utilized by mixing the gas with air and testing in the same manner. The main advantage of testing with sulfur hexafluoride is ease of detection and decreased equipment/maintenance costs of the detection equipment. 7.5.2 Plastic Film Testing A thin, plastic wrap material is placed over the area of the tubesheet to be tested at both the inlet and outlet ends of the condenser. Vacuum is maintained on the shell side. The plastic film will be pulled into the leaking tubes. A search is made for any areas where the wrap appears to be sucked into a tube. It is not necessary to cover the entire tubesheet at one time. A procedure can be adopted in which only a section of the tubesheet is covered and then inspected before moving on to the next section.

7-31


This method fails to detect small leaks and is ineffective for joint leaks. Each tube in a group might require separate testing by covering it with a small patch of plastic film. 7.5.3 Soap Film Testing Instead of plastic film at both ends of the unit in corresponding locations, the plastic film is only placed at one end of the unit with the opposite end being covered by soap foam. Any tube/joint leaks will cause a collapse of the foam in the leak area and thus reveal the leak location. This method can only be used to detect tube leaks and not small joint leaks. The foam most favored by technicians is shaving cream. Substantial quantities of shaving cream have been used at fossil and nuclear plants. The shaving cream is spread over the tubesheet, which is then inspected to see where the foam has been sucked into tubes. The leaking tubes are then plugged. 7.5.4 Non-Destructive Methods Other methods that can be utilized to detect leaks are infrared, eddy current sonic pulse, and ultrasound. Each of these methods is accurate and requires specially skilled personnel to perform. For a more complete discussion of these techniques see Recommended Practices for Operating and Maintaining Steam Surface Condensers [24]. 7.5.5 Smoke Method The smoke method has traditionally involved the use of a smoke generator. After the waterbox has been drained, a technician enters and partially closes the manway. The technician proceeds to light up and hold a smoke generator (often a cigarette) in front of individual tubes. It is observed if the smoke is drawn into the tube. The distance of the leak from the face of the tubesheet might affect the technician’s ability to make a positive identification of the leaking tube. 7.5.6 Rubber Stoppers Two types of rubber stoppers are available: solid rubber stoppers and specialty rubber stoppers with a thin membrane that covers a hole formed through the stopper. Both types have been used successfully to locate tube leaks when the condenser is under vacuum. To check a tube for leaks using solid rubber stoppers, one stopper should be installed in each end of the tube and allowed to stay in place for as long as 12 hours. If leaking, the tube is now under vacuum. When later removing the stopper from one end, personnel can confirm that the tube is leaking by noting the additional force that had to be exerted to remove the stopper. Specialty membrane rubber stoppers are used in conjunction with solid rubber stoppers. One of the membrane-type stoppers is installed in one end of the tube while a solid rubber stopper is placed in the other. The suction created within a leaking tube results in a visible depression on the membrane covering the end of the specialty rubber stopper. 7-32


Because membrane rubber stoppers do not require a long soak time, even small leaks can be detected in a few minutes. 7.5.7 Individual Tube Pressure/Vacuum Testing It is also possible to identify tube leaks by pressure or vacuum testing individual tubes. Testing is accomplished by blocking both ends of a suspect tube, pressurizing or evacuating the tube, and then observing if there is a loss of pressure or vacuum over a period of time. Additionally, pressure testing by pneumatic or hydrostatic means can be used to proof test a tube. A few minutes spent using this method to test one or two rows of tubes surrounding a suspect or leaking tube will not only confirm the leak but will also identify any additional leaking tubes. This might even eliminate the need to install insurance plugs. However, if the objective is to test the entire condenser, one of the other in-leakage test methods outlined earlier might offer a faster solution. 7.5.8 Hydrostatic Testing [25] Water filled leak or hydrostatic testing should be conducted prior to any coating operations or placement of the unit back into service. Water filled leak testing is normally employed as the final test for tube-to-tubesheet joint integrity. The specific procedure for hydrostatic testing of condenser tube joints is dependent upon the condenser system setup at the particular plant. However, a few general precautions and recommendations are suggested prior to and during condenser hydrostatic testing: x

Ensure that water temperature and metal temperature are maintained at a minimum of 60qF (16qC) during testing to prevent condensation from forming on the tubesheet. Condensation makes it difficult to determine the source of joint leaks.

x

The condenser should be filled slowly enough to ensure that all leakers can be identified and re-rolled. A good rule of thumb is to fill it at a rate of approximately 3 feet/hour (1.5 cm/min). If gross leaking occurs, filling should be stopped and all leakers re-rolled before reinitiating filling.

x

Leakers should first be re-rolled at the initial expansion torque. Should leaking continue, expansion torque should be increased in 6 inch-lb (677 mN-m) increments.

x

The condenser should be filled to a test height of 4 feet (1.2 meter) above the top of the bundles. After the test height has been reached, the level should be maintained for approximately 12 hours. The tubesheets should then be carefully reinspected. Should more than 5 to 10 weepers be found, the level should be maintained for an additional 12 hours.

7.5.9 Miscellaneous Problems Experience has shown that water in-leakage can be caused by some damage having been sustained by piping that had been allowed to run through a waterbox. An example would be drain piping from a low-pressure turbine bearing, which could be placed only vertically and immediately below the bearing, thus being forced to penetrate the waterbox. Leaks from such sources are hard to locate even when using sensitive tracer gas techniques, partly because they 7-33


are somewhat hidden from view, but often because their leak rates are very small. In addition to noting the obvious, the importance of studying plant drawings and identifying all such obscure sources of potential leaks cannot be stressed enough. 7.5.10 On-Line Leak Detection [26] Key Human Performance Point EPRI has developed and patented a system that uses targeted injection of sulfur hexafluoride (SF6) to detect and locate condenser tube leaks while the condenser is in full operation. The system is called the Condenser On-Line Leak Detection System (COLDS) and a description of it is found in EPRI document AP101840-V3P2, published in December 1995. It can locate leaks with flow rates as low as 1 gallon (4 liters) of water per day and small leaks that cannot be located with off-line techniques. Figure 7-8 shows the schematic of the COLDS.

7-34


Figure 7-8 Schematic Diagram of the EPRI COLDS [26]

In the COLDS, SF6 tracer gas is mixed with water and introduced into the condenser tubes through an injector that can be positioned selectively to direct the gas toward specific tubes. Leaks are detected by monitoring for the presence of SF6 in the off-gas, and the location of a leak is determined from the position of the injector when the SF6 is detected. The device used to detect the presence of SF6 in a gas sample is an electron-capture cell, comprised of two electrodes and a foil of radioactive nickel. A voltage difference is maintained across the two electrodes, causing a small electric current to flow across the air gap between the electrodes. The gas sample is pumped into the cell where it passes between the electrodes, is ionized by the radioactive foil, and supports a current flow across the gap. Because ionized SF6 captures electrons, the level of the current flow is reduced in proportion to the amount or 7-35


concentration of SF6 in the sample. With this technique, levels of SF6 down to 0.1 ppb are detectable. The lance assembly is designed to replace existing manway covers on inlet waterboxes and can be installed during an outage. The injection lance is positioned coaxially within a tubular housing. This is affixed to a swivel mount and passes through the port in a ball valve. The inner portion of the lance is inside the waterbox and the other end extends outside. The lance can be advanced and retracted axially within the housing; the swivel ball joint can be rotated to place the lance in a desired angular position. A range of areas and locations on the tubesheet can be targeted. The lance targeting method consumes less tracer gas than bulk injection does. This system is designed to monitor lance position by using linear variable differential transformers (LVDTs) coupled with a personal computer. An LVDT is a rugged electromechanical device that produces an electrical output proportional to the displacement of a movable core. In this system, three LVDTs, spaced equally about the axis of the lance, produce signals that are sent to the computer. These are used to determine the position of the lance relative to the condenser tubesheet.

7.6

Correcting Water In-Leakage [3]

Section 7.5 describes available methods for locating the source of water in-leakage. Having found the source and nature of the leak, it might be prudent to perform a failure analysis. It is not enough to correct the immediate problem; steps should be taken to determine the extent of the damage to other parts of the tube bundle by, for example, eddy current testing of a selected set of tubes. How to prevent or delay the occurrence of similar in-leakage problems in the future should be a strategic concern. If corrosion was due to deposits not being removed soon enough, then a more frequent tube cleaning program should be instituted. If the corrosion was caused by the chemical composition of the cooling water source, a chemical treatment program might need modifying. Perhaps the tube material is unsuitable for the available source of water. Possibly the corrosion was due to galvanic action between incompatible metals. All these failure modes require their own appropriate policy response. Some of the possible remedies available to correct these in-leakage problems include tube plugs, tube inserts or shields, tube sleeves, tube end coating, tube liners, full-length tube coating, reexpanding the tube-to-tubesheet joints, coating of tubesheets, retubing, staking tubes, waterbox repairs, tubesheet repairs, and miscellaneous repairs. If the water in-leakage was due to the erosion/corrosion of tube inlet ends, this can often be circumvented by placing plastic inserts, thin-walled metal inserts, or shields in the tube inlet ends. Sleeves can be installed in damaged sections of the tube. Coatings can be applied to tubes, tubesheets, and waterboxes to restore material surfaces. Damage from tube vibration can be reduced by staking the tube bundles appropriately. Please see Section 10 of this guide for information on maintenance repairs.

7-36


All of these can be considered as strategic approaches designed to extend the longevity of the condenser. However, severe tube damage can make retubing the condenser a necessity. Please see Section 11 of this guide for information on retubing and rebundling modifications.

7-37


8 FAILURE MODES

This section covers the failure data from the nuclear industry, specific failure mechanisms for the condenser, and general corrosion prevention practices.

8.1

Failure Data

There are several operational and maintenance databases available from the Institute of Nuclear Power Operations (INPO), the Nuclear Regulatory Commission (NRC), and the Operating Plant Experience Code (OPEC). INPO identifies and communicates lessons from plant events so that utilities can take action to prevent similar events at their plants. Events are screened and analyzed for significance and those with generic applicability are disseminated to the industry as Significant Event Evaluation and Information Network (SEE-IN) documents. The following are some applications that provide access to INPO and industry operating experience information: x

Just-in-Time (JIT) Operating Experience provides specially formatted training/briefing material to assist in preparing personnel to perform plant functions. The briefing material consists of important industry operating experience for specific functions compiled from the INPO SEE-IN library.

x

Significant Event Evaluation Information Network (SEE-IN) documents consist of several reports that communicate lessons learned from industry events. The reports include Operating Experience (OE), Significant Operating Experience Reports (SOERs), Significant Event Reports (SERs), Significant Event Notifications (SENs), and Operations and Maintenance Reminders (O&MRs).

x

The Plant Events Database contains industry event summaries prepared by INPO personnel as part of the INPO event screening process. This information is used for focused searches on event characteristics.

The following is an application from the NRC: x

The Licensee Event Reports (LERs) database contains searchable event information from the NRC reporting system. This information can be searched for plant events that have occurred since 1984.

Sections 8.1.1, 8.1.2, and 8.1.4 list the INPO reports that apply to the condenser. Section 8.1.3 lists the NRC reports, and Section 8.1.5 lists the OPEC events that apply to the condenser.

8-1

EPRI Licensed Material Failure Modes

8.1.1 Just-in-Time Operating Experience There have been four incidences of injuries from use of the hydrolaser. The hydrolaser is a device that cleans condenser tubes. Water at pressures up to 10,000 psi (69 megapascals) is supplied from high-pressure hoses to a nozzle attached to a lance. Personnel guide the lance to each condenser tube to inject the high-pressure water to clean debris from the tube. See Table 8-1 for a listing of the injuries. Table 8-1 Injuries from Hydrolaser Use (from INPO JIT data) Date

Injury

Cause

4/11/00

Small puncture in arm

Contractor did not use required safety protection equipment on lance.

7/20/99

Minor laceration on toe

Mechanic was not in correct position to hold Hydrolaser when trigger was depressed.

4/27/99

Laceration on finger

The hose of the wand became entangled and the left hand passed in front of the wand.

1/8/99

Severe hand cut

Worker was not prepared for the reaction force of the wand when the water was turned on.

Key Human Performance Point INPO determined that the following are causes of personnel injuries from Hydrolaser use: x x x

Improper work practices Inappropriate personal protection equipment Failure to implement operating experience

8.1.2 Significant Event Evaluation Information Network (SEE-IN) SEE-IN documents include: x

Operating Experience Reports (OEs)

x

Significant Operating Experience Reports (SOERs)

x

Significant Event Reports (SERs)

x

Significant Event Notifications (SENs)

x

Operations and Maintenance Reminders (O&MRs)

Table 8-2 lists the dates, notices, events, and description of events for main condenser equipment for the years 1981-2000. There have been twelve events during that time.

8-2

EPRI Licensed Material Failure Modes Table 8-2 INPO SEE-IN Experience Information Date of Notice 1/25/00

Plant

Event

Description

Farley 1

Power reduced to 62% because of leak in expansion bellows of extraction steam line

Expansion bellows cracked from fatigue caused by steam flow vibration and age.

Palo Verde 2

Unit shutdown on high sodium levels in steam generator

Condenser tube leak caused by 11 failed expansion joints from vibration-induced high-cycle fatigue.

Hatch 2

Low condenser vacuum manual scram due to waterbox air entrapment

The unit was manually scrammed on low condenser vacuum. The loss of vacuum resulted from waterbox air entrapment created by lowering the circulating water pump suction intake level for chlorination activities, an ineffective waterbox continuous vent modification, and atmospheric conditions.

Crystal River 3

Saltwater intrusion caused by main condenser tube rupture

Catastrophic failure of one condenser tube allowed ingress of saltwater into the hotwell. The condensate and feedwater systems were contaminated with chloride, sodium, and sulfate and the unit was shut down.

Sequoyah 2

Unit shutdown due to condenser tube leak and 5 Mw reduction

Failed extraction line bellows expansion joint.

Maine Yankee

Unit shutdown due to low, lowpressure steam supply to feedwater pump turbine

Failed extraction expansion joint.

OE 11065 1/5/00 OE 11554

7/30/99 SEN 200

4/19/96 SEN 130 SER 7-96

3/8/95 OE 7271 6/13/92 OE 5371

8-3

EPRI Licensed Material Failure Modes Table 8-2 (cont.) INPO SEE-IN Experience Information Date of Notice 2/28/91

Plant Zion

O&MR 385

Event

Description

Sudden loss of condenser vacuum due to condenser boot failure

9/90 - a 4-foot (1.2 m) section of the rubber condenser boot failed 8/89 - a 3- foot (91 cm) section of the condenser boot was torn 7/89 - condenser boot failure from aging, over-tightening bolts, and steam impingement 9/87 - an 8-foot (2.4 m) section of the rubber condenser boot failed 1/85 - condenser rubber boot failed 1&2/84 - condenser boot failure from overheating

Vermont Yankee

Steam intrusion into main condenser during maintenance

Steam intrusion into a taggedout condenser. A feed-water recirculating valve was open in the adjacent condenser that was con-nected to the tagged-out condenser by an equalizing line.

Peach Bottom 3

Unplanned radioactive release due to a blown fuse in the main condenser hotwell level control system

A blown fuse in the hotwell level control system allowed condensate to overflow the condensate storage tank, flow to the storm drain system, and into the river.

O&MR 276

Alabama Power, Penn. P & L

Legionella bacteria in plant cooling towers and condensers

Presence of legionella bacteria found in sludge. Respiratory protection required by two utilities.

7/14/83

San Onofre 2

Water hammer in steam bypass control system damaged condenser

Piping damage from water hammer in steam bypass control system.

Peach Bottom 2

Results of oil intrusion into main condenser hotwell

300 gallons (1,135 liters) of lubricating oil flowed from the feedwater pump bearings.

3/18/87 O&MR 318

2/16/86 SER 27-86

10/4/85

O&MR 148 8/12/81 SER 62-81

8.1.3 Licensee Event Reports (LERs) There are twenty-four LERs found for main condensers from 1984 to the present. Table 8-3 lists these events. Note that nine of these unit trips were the result of the condenser neck seal expansion joint failures and two of the trips were caused by condenser tube leaks. The subjects of condenser neck seal and extraction expansion joints are not covered in this guide but are 8-4


planned for coverage in an EPRI Expansion Joint guide scheduled for release in the 2001-2002 time period. Table 8-3 Licensee Event Reports for Main Condenser from 1984 to Present Date

Plant

Event-Reactor Trips

Description

11/16/97

Robinson 2

Low feedwater flow to steam generator

Condensate pump stub shaft failure, cyclic fatigue from faulty design on keyway.

11/26/95

Palo Verde 1

Turbine trip on low condenser vacuum

Faulty o-ring in solenoid caused two vacuum breaker valves to leak.

9/30/95

Brunswick 1

Condensate feedwater transient

Air in-leakage caused air binding in both condensate pumps.

7/17/92

Shearon Harris 1

Low condenser vacuum

Low-pressure turbine exhaust boot seal failure, routine fatigue by aging.

7/12/92

Shearon Harris 1


Low-pressure turbine exhaust boot seal failure, routine fatigue by aging.

6/24/92

Calvert Cliff 2


Failed condenser expansion joint due to aging.

12/20/91

Washington 2

High reactor coolant conductivity

Main condenser tube leak.

9/7/90

Zion 2

Loss of condenser vacuum

Condenser boot failure.

8/14/89

Grand Gulf 1


Condenser expansion joint failure.

7/16/89

Diablo Canyon 2

Condensate high cation conductivity

Condenser tubesheet plug failure.

7/14/89

Clinton


Failed rubber expansion joint from age, overtightening clamp assembly, and steam exposure from detached protection cover.

1/20/88

Grand Gulf 1

Low reactor water level

Leaking condenser water manway cover sprayed water on hotwell level switches.

6/1/87

D.C. Cook 2


Failed manual isolation valve allowed air in-leakage from the open drain tank discharge header.

4/9/87

Dresden 3

High condensate temperature and low condenser vacuum

Turbine bearing cone wastewater and oil drain line union broke inside condenser.

8-5


Table 8-3 (cont.) Licensee Event Reports for Main Condenser from 1984 to Present Date

Plant

Event-Reactor Trips

Description

3/26/87

Vogtle 1

Low-suction pressure on feedwater pump

Failure of condenser level transmitter locknut.

9/27/86

Dresden 3


Circulating water flow reversal valve failure.

7/26/86

San Onofre 3

Loss of feedwater

Automatic rejection of condensate contaminated by condenser seawater inleakage.

4/11/85

R. E. Ginna 1


Isolation and venting of condenser section to find baffle plate failure.

1/16/85

Quad Cities 2


Failed rubber expansion joint.

12/18/84

St. Lucie 2

Low steam generator level

Poor venting technique for condensate pump caused cavitation and pump trip.

8/2/84

Columbia 2

High reactor water conductivity

Condenser tube leak.

4/26/84

LaSalle 2

Manual scram to prevent equipment damage

Stuck recorder pen on the level recorder in the control room, suction strainers on condensate pumps plugged.

2/13/84

LaSalle 1


14 stage extraction expansion joint failed, rupturing the boot seal between the condenser and turbine.

1/16/84

LaSalle 1


16 stage extraction expansion joint ruptured and caused the rubber boot seal to rupture.

th

th

8.1.4 Plant Events Database The Plant Events Database contained fifty-five events from1990 to the present for the condensers. Twenty-three events were selected based on the failed component. Note that of the twenty-three events selected, six events were condenser tube leaks and six events were failures of the condenser neck seal expansion joint. See Table 8-4 for these events. The subjects of condenser neck seal and extraction expansion joints are not covered in this guide but are planned for coverage in an EPRI Expansion Joint guide scheduled for release in the 2001-2002 time period.

8-6

EPRI Licensed Material Failure Modes Table 8-4 INPO Plant Events Database for Condensers Date

Plant

Event

Failure

9/18/00

Columbia 2

Decrease in vacuum

Turbine oil, water drain broke in condenser.

9/13/00

Vermont Yankee 1

Loss of vacuum

Ejector steam supply valve closed on loss of motor power.

8/31/00

Diablo Canyon 2

Extraction line expansion bellows failure

Damaged condenser tube causing leaks.

6/6,7, 18/99

LaSalle 1

Leakage from lower manway on condenser

Improper gasket material, poor condition of manway sealing surface, and bolts insufficiently tightened.

2/21/99

Grand Gulf 1

Manual scram for decreasing condenser vacuum

Condenser seal improperly vulcanized and joint failed.

12/3/98

Peach Bottom 3

Condenser tube leaks

Baffles were not deflecting steam from impinging on tubes.

11/14/98

Surry 1

Water chemistry chloride and sodium levels in condensate too high

Tube plugs missing.

6/3/98

Oconee 2


Vacuum was lost through an open auxiliary steam valve during maintenance.

5/20/98

Ark. Nuc. One 1

High sulfate concentration in condensate


9/10/97

Fort Calhoun 1

High levels of sodium in condensate


4/22/97

E.I. Hatch 2


Loss of ejector and air entrainment in the circulating water system.

1/9/96

Crystal River 3

High levels of chloride, sodium, and sulfate in condensate


7/14/95

D.C. Cook 1


Broken weld on a 1-inch steam dump valve drain allowed air intrusion.

7/12/95

Grand Gulf 1


Degradation of condenser expansion joint seal.

3/8/95

Sequoyah 2

Condenser tube leak

Extraction line bellows had blown out.

8-7

EPRI Licensed Material Failure Modes Table 8-4 (cont.) INPO Plant Events Database for Condensers Date

Plant

Event

Failure

4/29/94

Millstone 3

Condenser waterbox rupture

Outlet valve closed in fullflow conditions due to an inadequately designed spline adapter to the shaft interface.

1/11/94

Catawba 1


Heater extraction line sheared off from vibrationinduced fatigue.

11/4/93

Three Mi. Island 1

Partial loss of condenser vacuum

Improper installation of diaphragm in air-operated solenoid valve for the airremoval pump discharge valve that allowed air inleakage.

10/22/93

E.I. Hatch 1

Condensate pumps tripped

Partition plate in condenser broke and hit a brace. This caused vibration that tripped the hotwell level switch.

7/17/92

Shearon Harris 1


Failure of the turbine exhaust boot seal.

7/12/92

Shearon Harris 1


Repair of condenser expansion joint.

6/24/92

Calvert Cliffs 2


Failed condenser expansion joint.

11/16/91

Clinton 1

vacuum

Condenser suction isolation valve open.

Decreasing condenser

9/7/90

Zion 2


Failed expansion boot.

7/15/90

Limerick 2


Low-pressure turbine waste oil drain pipe failure.

8.1.5 Operating Plant Experience Code (OPEC) Failure event data was obtained from the OPEC. Table 8-5 lists the events for condenser tube leaks from April 1998 through June 2000. For the twenty-seven months of the data given, there were forty-four outage events because of tube leaks. Of these forty-four events, twenty-six events resulted in a forced outage, sixteen events resulted in a scheduled outage, with two events unknown.

8-8

EPRI Licensed Material Failure Modes Table 8-5 OPEC Data for Condenser Tube Leak Events from 4/1998 to 6/2000 Date

Plant

Outage Type

Event

06/28/00

Beaver Valley 2

Forced

Load reduction to 90%

06/26/00

Calvert Cliffs 1

Forced


04/08/00

Robinson 2

Scheduled


03/28/00

Turkey Point 4

Unknown


03/18/00

Robinson 2

Scheduled


03/10/00

Three Mi. Island 1

Forced


01/28/00

Nine Mi. Point 1

Forced


01/08/00

FitzPatrick

Scheduled

Load reduction

01/06/00

Palo Verde 2

Scheduled

Off-line tube plugging

01/06/00

Palo Verde 2

Forced

Shutdown

11/18/99

Oyster Creek

Forced


11/04/99

FitzPatrick

Forced

Load reduction

10/30/99

FitzPatrick

Forced

Load reduction

10/05/99

Beaver Valley 2

Scheduled


10/01/99

Beaver Valley 1

Scheduled


08/06/99

Beaver Valley 1

Forced


07/10/99

Peach Bottom 3

Forced


06/01/99

North Anna 1

Unknown


05/12/99

Hope Creek 1

Forced

Load reduction

05/07/99

Palisades

Scheduled


04/30/99

LaSalle 2

Forced

Load reduction

04/16/99

Ark. Nuc. One 2

Scheduled


04/12/99

North Anna 1

Forced


04/09/99

Fermi 2

Scheduled


03/16/99

Diablo Canyon 1

Forced


02/24/99

Beaver Valley 1

Forced


02/14/99

Beaver Valley 1

Forced

Shutdown

01/01/99

Watts Bar 1

Forced


8-9


Table 8-5 (cont.) OPEC Data for Condenser Tube Leak Events from 4/1998 to 6/2000 Date

Plant

Outage Type

Event

12/04/98

Summer 1

Scheduled

Load reduction

12/21/98

Hope Creek 1

Forced

Load reduction

10/28/98

Millstone 3

Forced

Shutdown

09/25/98

Palisades

Scheduled


09/12/98

Hope Creek 1

Forced

Load reduction

08/27/98

Millstone 3

Scheduled

Load reduction

08/27/98

Watts Bar 1

Forced


08/21/98

Shearon Harris 1

Scheduled


07/19/98

Perry 1

Forced

Load reduction

06/07/98

Ark. Nuc. One 2

Forced


05/21/98

Three Mi. Island 1

Scheduled


05/20/98

Ark. Nuc. One 2

Forced

Shutdown

05/08/98

Ark. Nuc. One 2

Forced


04/24/98

Three Mi. Island 1

Scheduled


04/24/98

Shearon Harris 1

Scheduled


04/13/98

Watts Bar 1

Forced


8.2

Failure Mechanisms [27]

While there are numerous failure mechanisms for condenser components, this report will address the top eleven mechanisms. With each mechanism a failure prevention practice is included. 8.2.1 Condensate Corrosion Condensate corrosion is a localized form of corrosion that affects the steam side of copper tubes. This is commonly known as grooving and often occurs adjacent to the tube support plates in the air-removal section. Deep circumferential grooves can occur in areas of localized condensate flow. Oxygenated, ammonia-rich condensate runs in rivulets down support plates and onto tubes. The corrosivity of the condensate is reduced by adding chemicals to scavenge oxygen and buffer pH. These chemicals, typically hydrazine and various amines, can undergo thermal decomposition in the high temperature zones of the reactor/boiler to form ammonia. This ammonia, along with other non-condensable gases, tends to collect in the air-removal section of the condenser. These non-condensable gases dissolve in the condensate, resulting in an oxygenated, ammonia-rich condensate that can be severely corrosive to copper-alloy tubes, particularly the brasses. The presence of carbon dioxide will tend to increase the severity of the problem.

8-10


Failure Prevention Practice — Reduce the oxygen levels and use a stainless steel or titanium tube material. 8.2.2 Crevice Corrosion Crevice corrosion occurs on the inside of condenser tubes and in the tube-to-tubesheet joints. The corrosion occurs wherever there is a narrow crevice or area that is shielded from direct exposure to the cooling water. Corrosion is accelerated inside or immediately adjacent to the crevice. This can occur at the tube-to-tubesheet joint, at the interface between inlet end inserts, or beneath deposits. Crevice corrosion has been reported in stainless steel and copper-alloy tubes. Crevice corrosion susceptibility is increased with increasing water temperature or chloride concentration. It is also influenced by the tightness of the crevice. A picture of crevice corrosion is shown in Figure 8-1.

Figure 8-1 Crevice Corrosion [24]

Failure Prevention Practice — Eliminate tube-to-tubesheet crevice by seal welding the joints in stainless steel tubes, apply cathodic protection, or apply protective coatings to the tubesheet. 8.2.3 Dealloying [28] Dealloying is the selective removal of the more active components of an alloy by an electrochemical process. Dealloying occurs on the tubesheet and waterbox. It can be difficult to detect visually because of the lack of significant dimensional change.

8-11


Muntz metal is composed of ~60% copper and ~40% zinc (ASTM B171). For tubesheets made of Muntz metal, a dealloyed area will often exhibit a bright copper-colored appearance once the thin, dull surface layer is removed. If dealloying is suspected, the area should be probed with a knife or chisel to detect the presence of a weak, spongy structure. The most common dealloying mechanism is dezincification, the selective leaching of zinc from brass alloys. Dealuminumification involves the loss of aluminum and denickelification the loss of nickel. Dealloying also occurs in cast-iron waterboxes, where iron is selectively removed, leaving a graphite layer. This form of dealloying is known as graphitization. Dezincification is encountered in two forms: layer and plug attack. Layer-type attack is similar to general corrosion, with little or no discernible change in overall dimensions. In the case of copper-based alloys, the surface appears reddish at areas where the active component has dissolved. This attack occurs in low hardness, low pH waters under stagnant conditions, and is accelerated by chloride and sulfate ions. Differential oxygen cells beneath deposits can also promote attack. Plug-type dezincification is similar to pitting attack. This is the more dangerous form because attack can cause failure through penetration. This localized attack usually attains a significant depth perpendicular to the metal surface. It is promoted by alkaline corrosive media, local deposits, and discontinuities in the protective oxide film. Aluminum brass is particularly prone to such attack. Figure 8-2 shows a picture of plug-type dezincification.

Figure 8-2 Plug-Type Dezincification Magnified Cross-Sectional and Planar Views [24]

The mechanism for dezincification falls into two categories: x

Selective dissolution of zinc, which leaves the copper intact

x

Simultaneous dissolution of both principal elements followed by subsequent redeposition of copper

8-12


Depending on the various solution factors, it is highly probable that both mechanisms occur at the same time. The seriousness of the attack on commercial brasses depends on the application. For brasses used in heat exchanger tubes, plug-type dezincification becomes more serious because of its depth of penetration relative to overall tube wall thickness. The same type of attack on tubesheets has negligible consequences. Layer dezincification might waste more metal from the entire surface than plug attack but it is a less serious condition. Key Technical Point Dezincification of Muntz metal is the most commonly reported dealloying problem in condensers. In the absence of other corrosion accelerating factors, Muntz metal tubesheets are normally thick enough (nominally 1 to 1.5 inches (2.5 to 3.8 cm)) to withstand the dezincification that occurs. However, in cases where galvanic-induced corrosion is significant, such as a Muntz metal tubesheet fitted with titanium tubes, dezincification has occurred at penetration rates exceeding 0.5 inches (1.3 cm) per year. Many factors influence the dezincification of brasses. Drained condensers containing wet areas can undergo tube dezincification. This is because stagnant water at such sites has a reduced oxygen supply, which is conducive to attack. Wet areas under crevices or debris will increase the possibility of dezincification. High chlorides, especially the levels found in brackish water or seawater, are another common cause. These waters are highly conductive and chlorides easily penetrate the oxide layer. Local pH suppression can have a great impact. Hydrolysis of copper salts on the metal surface will produce an acidic environment that will preferentially dissolve zinc. Porous deposits restrict the access of oxygen (differential aeration) and sustain dezincification attack at the site. Scale caused by hardness salts typifies the formation of porous deposits or film on condenser tubes. Elevated temperature greatly accelerates dezincification, especially at local hot spots. Dezincification of admiralty brass has been significantly reduced by alloying with either arsenic, phosphorous, or antimony. Aluminum brass will suffer plug-type dezincification unless alloyed with arsenic. Further control can be achieved by adding chemical inhibitors to the cooling water. The azoles are extremely effective in controlling this form of attack. Table 8-6 shows the component dealloying mechanisms for different material components. Table 8-6 Component Dealloying Mechanisms Component

Dealloying Mechanism

Brass tubes

Dezincification

Copper-nickel tubes

Denickelification

Brass tubesheets

Dezincification

Aluminum bronze tubesheets

Dealuminumification

Cast-iron waterboxes

Graphitization or Graphitic corrosion

8-13


Failure Prevention Practice – No practice is recommended as the thickness of the tubesheet or waterbox is sufficient for the dealloying to occur over a forty-year life. If the dealloying is coupled with galvanic corrosion, then cathodic protection or coating the tubesheet is recommended. Control of dezincification of admiralty brasses has been achieved with material changes and water chemical treatment. 8.2.4 Erosion-Corrosion Erosion-corrosion is a relatively common problem on the inside of copper-alloy tubes. It occurs because of the effects of flow and does not occur when the cooling water is still. It is usually a localized form of corrosion because it depends on the geometry of the system to direct the water flow. Bends in pipes, elbows, tees, pump impellers, and valves are especially susceptible. Erosion-corrosion-induced metal loss in a tube often exhibits patterns such as undercut grooves, waves, ruts, gullies, and rounded holes. There is often a directional pattern. Pits are elongated in the direction of flow and are undercut on the downstream side. When the conditions become severe, it might result in a pattern of horseshoe-shaped grooves or pits with their open ends pointing downstream. See Figure 8-3 for an example of inlet end erosion-corrosion.

Figure 8-3 Inlet End Erosion-Corrosion [24]

Erosion-corrosion occurs because the flow-induced turbulence of the cooling water disrupts and removes the protective oxide films from the surface of the copper-alloy tubes. Titanium and stainless steel-alloy tubes are not affected because their oxide films are quite stable in the turbulent flows typical of condensers. Turbulence increases with increasing velocity and is greatly influenced by geometry. At tube inlets, turbulence is more intense than several feet down the tubes. This results in the phenomenon known as inlet erosion-corrosion. If a tube becomes partially plugged with debris such as a mussel shell, a localized region of high velocity and turbulence can result around the restricted opening with the consequent occurrence of erosion-corrosion downstream of the 8-14


lodged debris. This form of erosion-corrosion in a tube is often referred to as lodgement corrosion. See Figure 8-4 for a picture of a rock lodged in a tube causing erosion-corrosion.

Figure 8-4 Erosion-Corrosion From a Lodged Rock in a Tube [24]

Some suggested maximum velocities are shown in Table 8-7. While these velocities are for condenser tube alloys in seawater, the data should also generally apply to other types of heat exchangers and other types of waters. Table 8-7 Suggested Critical Velocity Limits for Condenser Tube Alloys in Seawater (courtesy of F.L. LaQue, Marine Corrosion Causes and Prevention, Wiley, p. 147.) Material

Recommended Maximum Velocity Feet/second

Meters/second

Copper

3

0.9

Admiralty Brass

5

1.5

Aluminum Brass

8

2.4

90-10 Cu-Ni

10

3.0

70-30 Cu-Ni

12

3.7

Type 316 Stainless Steel

No maximum velocity limit

Titanium

No maximum velocity limit

Erosion-corrosion can be exacerbated by entrained air/foreign particles such as silt or sand or pollutants (for example, sulfides) in the cooling water. Failure Prevention Practice – Measures for preventing erosion-corrosion in condenser tubes are: x

Substitute more resistant tube alloys

x

Use inlet tube inserts

x

Apply cathodic protection to inlet tubesheet 8-15


x

Install vanes or diffusers to reduce inlet turbulence

x

Clean to remove tube lodgments and foreign debris

x

Reverse flow periodically to dislodge materials

x

Apply protective coating to inlet tubes

8.2.5 Galvanic Corrosion Galvanic or dissimilar metal corrosion occurs on waterboxes and tubesheets. The corrosion of the tubesheets occurs when the tubesheet is coupled to electrochemically more noble tubes in cooling water of sufficiently high conductivity. Due to a potential difference between dissimilar metals, electrons flow from an anode (least noble metal) to the cathode (most noble metal). Generally the cathode does not corrode but the anode corrodes rapidly. Depending on the combination of dissimilar tube and tubesheet materials, significant metal loss can occur in very short periods, especially in the ligament area between tubes. Corrosion rates approaching 1 inch (2.5 cm) per year have been observed. Because the metals used for condenser tubes are nobler than those in other condenser components, a cathodic protection system is sometimes installed to protect the more vulnerable tubesheets and waterboxes from galvanic corrosion. In such cases, tube manufacturers should be consulted about the level of cathodic protection needed. Under certain circumstances, too high a protection for tubesheets and waterboxes can be damaging to the tubes. Key Technical Point The primary factors affecting the magnitude of current flow and rate of galvanic corrosion are the potential differences between the metals, the environmental aspects of the electrolyte, the polarization behavior of the respective metals, and the relative areas of the coupled metal. The environmental factors having the greatest effect in the galvanic corrosion rate are cooling water conductivity and temperature. Galvanic corrosion rates will increase with an increase in cooling water conductivity and temperature. Depending on material combination, chlorination of the cooling water can also have an important effect. Table 8-8 lists galvanic potential differences of some materials that are commonly used in condensers, when the cooling medium is saltwater.

8-16

EPRI Licensed Material Failure Modes Table 8-8 Galvanic Potential Differences for Typical Metals and Alloys [27] Metal or Alloy

Approximate Voltage

Titanium

0.00

316 Stainless steel

-0.18

70-30 Copper Nickel

-0.25

Aluminum Bronze

-0.26

90-10 Copper Nickel

-0.28

Admiralty brass

-0.40

Carbon Steel

-0.61

Cast-iron

-0.61

Zinc

-1.03

Aluminum

-1.60

Failure Prevention Practice – Cathodic protection or applying protective coatings and chlorinated water treatment is recommended. 8.2.6 General Surface Corrosion General corrosion occurs on the inside of tubes, tubesheets, and waterboxes. This is also known as tube wall thinning. It is characterized by relatively uniform metal loss due to corrosion along the entire length of the tube. Rates for titanium tube materials have been measured at 0.001 mil/yr (25.4 nm/yr) and between 0.5 and 2 mil/yr (12.7 and 50.7 nm/yr) for copper tube material. Failure Prevention Practice – Cathodic protection or applying protective coatings can mitigate some general corrosion attacks on condenser components. 8.2.7 Hydrogen Damage Hydrogen damage occurs on the inside of stainless steel and titanium tubes. It is not a common occurrence but hydrogen stress cracking and hydriding have been observed. Copper-alloy tubes are immune to this failure mechanism. Titanium and ferritic stainless steel tubes can incur damage where cathodic protection is installed in the waterboxes. For titanium tubes, the hydrogen generated by the passage of too high a cathodic protection current reacts with the metal to form a brittle titanium hydride phase in the microstructure. For ferritic stainless steel tubes, the passage of too high a cathodic protection current to the tube service can generate hydrogen at the surface. The hydrogen diffuses into the metal and can cause stress cracking, especially near the tube ends. This is where roller expansion during installation results in higher than normal residual stresses. Failure Prevention Practice – The prevention measures include designing a cathodic protection system to prevent polarization of tubes with a lower cathodic protection current or applying protective coatings to the tubesheet and waterbox. 8-17


8.2.8 Random Pitting Pitting is a form of localized corrosion that occurs on the inside of tubes, tubesheets and waterboxes. This type of corrosion is also referred to as microbiologically influenced corrosion (MIC). Key Technical Point Random pitting along the length of a condenser tube is the most commonly encountered condenser corrosion problem. Pitting is manifested most frequently in copper tubes but stainless steel is also susceptible. The localized penetration rates can be high enough to cause rapid perforation of thin wall tubing. Pitting occurs when a passive film or other protective film on a metal surface breaks down. Pitting susceptibility is usually increased with chloride and sulfide concentrations or temperature. Pitting in copper alloys can be caused by sulfides that prevent formation of a corrosion protective film. Decaying organic matter left in the tubes during outages can generate sulfides. Also, pitting along the bottom of the condenser tubes can be caused by sulfide-laden silt that often settles there. A sulfide concentration of as low as 0.01 ppm can be detrimental to copper alloys. It should be noted that sulfide does not become aggressive until exposed to oxygenated water. Consequently, sulfide attacks invariably occur during plant operation. This masks the fact that lay-up is the real cause of the problem. See Figure 8-5 for an example of pitting corrosion.

Figure 8-5 Pitting Corrosion of 304 SS Tubes, Magnified Cross-Section and Planar Views [24]

In addition, manganese can cause pitting damage to stainless steel tube materials. Manganese dioxide (MnO2) is a strong oxidizing agent that reacts with ferrous metals. MnO2 deposits that physically contact the tube surface serve as a galvanic cathode to support corrosion of the metal. For mild steel, the consequence of MnO2 deposition is limited to a slight increase in corrosion rate resulting from increased cathodic current. For stainless steel, the electrochemical effects of MnO2 deposition can promote pitting and crevice corrosion, causing rapid perforation of the tube walls. 8-18


Oxidizing biocides including halogens, peroxides, and ozone all have the capacity to oxidize dissolved manganese to MnO2. When halogens are used to control biofouling in waters that contain dissolved manganese, the resultant MnO2 and chloride create an aggressive environment for stainless steel. As a consequence, chlorination intended to control microbiologically influenced corrosion could promote corrosion failures in the system. The established methods for removing MnO2 deposits are mechanical removal using scrapers or chemical cleaning. For more information on the manganese dependent corrosion in stainless steel tube materials, please see “Manganese-Dependent Corrosion in an Open Service Water System” [29]. Failure Prevention Practice – The prevention measures are to keep the tubes clean, avoid stagnant lay-ups for long periods, flush during outages, prevent excessive biological fouling, and chemically treat water if needed. 8.2.9 Steam Side Erosion Steam side erosion is also known as impingement and occurs on the outside of tubes. Steam side erosion manifests on the periphery of the tube bundle in areas under the exhaust flow sections of the turbine. In the early stages, the tube exhibits a polished appearance. As the attack continues the surface becomes coarser, like sandpaper, until a leak ultimately develops. Key Technical Point Steam side erosion occurs as a result of wet steam or entrained water droplets traveling at a high speed and impacting on the surface of the tubes. The severity of impingement attack is a function of the kinetic energy of the fluid, the impact velocity, the mass flow per unit area, the hardness of the tube material, and the exposure time. Failure Prevention Practice – The prevention measures are to use more resistant materials such as stainless steel or titanium, use protector shields (protective jacket of stainless steel around peripheral tubes), and use impingement baffles (perforated plates or grids). 8.2.10 Stress Corrosion Cracking Stress corrosion cracking is a problem for the outside of copper-alloy tubes, particularly brasses. For stress corrosion cracking to occur, there must be a tensile stress in addition to a corrosive environment. Copper alloys are susceptible to stress corrosion cracking in an ammonia environment. See Figure 8-6 for a picture of stress corrosion cracking.

8-19


Figure 8-6 Stress Corrosion Cracking of Admiralty Brass, Magnified Cross-Section and Planar Views [24]

Failure Prevention Practice – The prevention measures are to keep the oxygen level low, use stainless steel in air-removal sections, and keep the tubes clean. 8.2.11 Vibration Damage Vibration is a flow-induced problem that occurs at or near the outer periphery of the tube bundle. This is where the velocities are highest. Localized wear and wall thinning are typically observed at the tube mid-span between support plates. Fretting, characterized by formation of powder deposits, is observed at the tube support points. Fatigue cracking is usually observed at mid-span and sometimes occurs at support plates. Condenser tubes also tend to vibrate under the influence of cross-flow velocities. These velocities tend to be highest near exhaust trunks or steam dumps. High velocity results in excessive vibration. This results in tube collisions at mid-span (point of maximum amplitude) between support plates. These collisions cause localized wear, wall thinning and fatigue. Smaller amplitude vibrations also cause fretting and fatigue damage at tube support points. Key Technical Point Flow-induced vibration damage occurs in condensers because the spacing between supports is too large or because the baffling at high-energy inlet connections does not provide adequate dispersion of the flow jet at the connection. The increasing use of thin wall tubing such as titanium or stainless steel makes destructive vibration even more likely. The low modulus of elasticity and the thin wall of a typical titanium tube produce a greater deflection in vibration.

8-20


Failure Prevention Practice – Preventive measures for vibration damage are to install additional tube supports, stake the tube bundle around the periphery, install additional flowdispersion baffling, and reduce volumetric flow into the condenser. 8.2.12 Summary of Failure Mechanisms The following table, Table 8-9, is a summary of failure mechanisms, the affected components, and the failure prevention practice for condensers. Table 8-9 Condenser Failure Mechanisms and Affected Components Failure Mechanism Condensate Corrosion Section 8.2.1 Crevice Corrosion Section 8.2.2

Affected Component(s) Water side of tubes

Dealloying Section 8.2.3

Water side of tubesheet, waterbox

Erosion-Corrosion Section 8.2.4

Water side of tubes

Galvanic Corrosion Section 8.2.5

Water side of tubesheet, waterbox

General Surface Corrosion Section 8.2.6 Hydrogen Damage Section 8.2.7 Random Pitting Section 8.2.8

Water side of tubes, tubesheet, waterbox Water side of tubes

Steam Side Erosion Section 8.2.9

Steam side of tubes

Stress Corrosion Cracking Section 8.2.10

Steam side of tubes

Vibration Damage Section 8.2.11

Steam side of tubes

Water side of tubes, tubesheet

Water side of tubes, tubesheet, waterbox

Prevention Practice Reduce oxygen levels, use stainless steel or titanium tube material. Seal weld joints, apply cathodic protection or apply coating to the tubesheet. If galvanic corrosion, use cathodic protection or use protective coatings. For dezincification, change materials and use chemical treatment or apply protective coatings. Substitute resistant tube alloys, use inlet tube inserts, cathodic protection, modifications for inlet turbulence, clean tubes, reverse flow, apply coating to inlet tubes. Cathodic protection, chlorinated water treatment or apply protective coatings. Cathodic protection or apply protective coatings. Lower cathodic protection current or coat the tubesheet and waterbox. Keep tubes clean, avoid stagnant lay-ups, flush during outages, prevent excessive biological fouling, and chemically treat water. Substitute resistant tube alloys, use protector shield and impingement baffles. Keep oxygen level low, use stainless steel in air-removal sections, keep tubes clean. Install additional tube support, stake the tube bundle, install additional flow-dispersion baffling, and reduce volumetric flow into the condenser.

8-21


8.3

General Corrosion Prevention Practices [27]

Because of the prevalence of corrosion failure mechanisms on condenser components, it is important to prevent these mechanisms from damaging the condenser. These practices were referred to in the previous section and are expanded in this section. The following are ten general corrosion prevention practices that can protect the condenser: x

Cathodic protection

x

Debris filtration/removal

x

Proper lay-up

x

Design modifications

x

Prevention of biofouling – covered in Section 5.2 (macrofouling) and Section 5.4 (microfouling) of this guide

x

Tube inserts – covered in Section 10.2 of this guide

x

Water treatment – covered in Sections 5.2.6 (macrofouling) and 5.4.2 (microfouling) of this guide

x

Cleaning – covered in Section 6 of this guide

x

Protective coatings – covered in Sections 10.4 (tube end), 10.6 (full-length tube), 10.8 (tubesheet), and 10.10 (waterbox) of this guide

x

Alloy substitution – covered in Sections 11.2, 11.3, and 11.4 of this guide

8.3.1 Cathodic Protection The purpose of installing cathodic protection is to mitigate inlet end erosion-corrosion of tubes, tube-induced galvanic corrosion of dissimilar tube-to-tubesheet materials, tube-to-tubesheetinduced galvanic corrosion of dissimilar waterbox materials, and general corrosion of the waterbox. Cathodic protection is a water side control method that arrests corrosion by creating an artificial environment. There are two types of cathodic protection systems: x

Sacrificial Anode Systems – The sacrificial anode cathodic protection system uses sacrificial (consumable) anodes that are bolted on waterbox walls at strategic locations. Anode materials are magnesium (predominantly for low conductivity in freshwater), aluminum alloy, or zinc (for all other cooling waters). Zinc is the most extensively used material. Galvanic corrosion is assured when one attaches zinc anodes to the waterbox walls. However, all corrosion will occur at the consumable anodes; thus, the waterboxes and tubesheets are protected. Continued cathodic protection effectiveness is maintained by periodic inspections of anode condition and replacement as required.

8-22


x

Impressed Current Systems – The impressed current cathodic protection system typically uses long-life or non-consumable anodes that are mounted through the waterbox walls. A direct current rectifier is used to super-impose potential and current on the anodes and condenser water side components. Sufficient potential current is provided to reverse the natural potentials and currents associated with component corrosion, thus eliminating corrosion. By doing this, condenser water side components become cathodic (do not corrode) and the cathodic protection anodes are anodic (either corrode slowly or support other noncorrosive oxidation reactions).

When considering a cathodic protection system, it is important to remember: x

In areas of tidal flow, the conductivity of the cooling water can have wide variations.

x

Impressed current systems should be a high visibility item for operations and/or maintenance personnel. If the system malfunctions, there is no cathodic protection.

x

When the circulating water system is shut down, there is no cathodic protection. Cooling water continues to drain from the tubes and corrosion can occur. For downtime situations of several days or more, it is recommended that the tubes, tubesheets, and waterboxes be flushed with potable water. More discussion of lay-up recommendations is given in Section 8.3.3.

The following tables list different combinations of materials for the condenser tubes, tubesheet, and waterbox components and the corresponding recommended protection practices for galvanic corrosion. Table 8-10 is for freshwater applications and Table 8-11 is for salt/brackish water applications.

8-23

EPRI Licensed Material Failure Modes Table 8-10 Freshwater Condenser Materials and Galvanic Corrosion Protection Applications [27] Tube Material

Tubesheet Material

Waterbox Material

Admiralty Brass

Muntz metal or Aluminum bronze

Carbon steel

Protective coating/ cathodic protection of waterbox


Cast-iron

None

Carbon steel

Carbon steel

Protective coating on waterbox and tubesheet, cathodic protection of tubesheet and waterbox


Carbon steel



Cast-iron

None

Carbon steel

Carbon steel

Protective coating on waterbox and tubesheet, cathodic protection of tubesheet and waterbox


Carbon steel



Cast-iron

None

Carbon steel

Carbon steel

Protective coating on waterbox and tubesheet cathodic protection of tubesheet and waterbox

90-10 Cu Ni

304 SS

8-24

Corrosion Protection

EPRI Licensed Material Failure Modes Table 8-10 (cont.) Freshwater Condenser Materials and Galvanic Corrosion Protection Applications [27] Tube Material Titanium

Tubesheet Material

Waterbox Material

Corrosion Protection

Solid titanium or carbon steel clad with titanium

Solid 316 or 317 SS or carbon steel clad with 316 or 317 SS

None

316 or 317 SS

316 or 317 SS

None

Solid titanium or carbon steel clad with titanium

Cast-iron or carbon steel


Copper alloy



Carbon steel

Copper nickel


Table 8-11 Salt/Brackish Water Condenser Materials and Galvanic Corrosion Protection Applications [27] Tube Material Stainless steel

Tubesheet Material 316 or 317 SS 316 or 317 SS

Waterbox Material 316 or 317 SS Cast-iron or carbon steel

Aluminum bronze

Aluminum bronze

Aluminum bronze


Muntz metal


Naval Brass


Silicon Bronze


Corrosion Protection None Protective coating/cathodic protection of waterbox Protective coating/cathodic protection of waterbox and tubesheet Protective coating/cathodic protection of waterbox and tubesheet Protective coating/cathodic protection of waterbox and tubesheet Protective coating/cathodic protection of waterbox and tubesheet Protective coating/cathodic protection of waterbox and tubesheet

8-25

EPRI Licensed Material Failure Modes Table 8-11 (cont.) Salt/Brackish Water Condenser Materials and Galvanic Corrosion Protection Applications [27] Tube Material Stainless steel (cont.)

Tubesheet Material Copper nickel

Waterbox Material Cast-iron or carbon steel

Copper Alloys 90-10 CuNi, 70-30 CuNi, Aluminum brass

Copper alloy, Muntz metal, Aluminum bronze, Naval brass, Silicon bronze, Copper nickel Solid titanium or carbon steel clad with titanium Solid titanium or carbon steel clad with titanium 316 or 317 SS 316 or 317 SS


Titanium

Solid 316 or 317 SS or carbon steel clad with 316 or 317 SS Cast-iron or carbon steel 316 or 317 SS Cast-iron or carbon steel

Aluminum bronze

Aluminum bronze

Aluminum bronze


Muntz metal


Naval brass


Silicon brass


Copper nickel


Corrosion Protection Protective coating/cathodic protection of waterbox and tubesheet Protective coating/cathodic protection of waterbox

None

Protective coating/cathodic protection of waterbox None Protective coating/cathodic protection of waterbox Protective coating/cathodic protection of waterbox Protective coating/cathodic protection of waterbox Protective coating/cathodic protection of waterbox Protective coating/cathodic protection of waterbox Protective coating/cathodic protection of waterbox Protective coating/cathodic protection of waterbox

8.3.2 Debris Filtration/Removal Effective filtration and removal of debris and fouling from a condenser will help to prevent inletend and lodgment corrosion of tubes. Gross debris in the cooling water is usually removed by trash racks, trash rakes, and flow-through traveling screens. One additional measure is to add an in-line strainer between the circulating water pump and inlet waterbox. Another measure is to add a debris filter in the pipe to the inlet waterbox. These additions require additional piping and valves. For more information on debris filters, refer to Section 5.2.1.4.

8-26


8.3.3 Proper Lay-Up A major cause of condenser corrosion problems is the condition in which the condenser exists during an outage. In most cases, the tube side is permitted to drain through the circulating water pipe or through the waterbox drain line once the vacuum is broken. Condensers are seldom cleaned during short outages. During long outages, condensers might be cleaned at the end of the outage if the schedule permits. Lay-up of a fouled condenser, especially one that is not vented, can be a source of potential corrosion. Key Human Performance Point Lay-up refers to all measures taken to prevent significant condenser corrosion during outages. Exposure of condenser parts to stagnant water during lay-up can lead to accelerated, localized corrosion. Given below are a few recommendations for short-, medium-, and long-term condenser lay-up. x

Short-term lay-up is defined as a maximum of two days. The hotwell should be left full of condensate. Circulating water, preferably containing biocides, should be pumped at least once a day for a minimum of thirty minutes. The purpose of this circulation is to relocate the solids that might have settled on the tube surfaces and to limit the production of corrosive substances from decaying organic matter.

x

Medium-term is defined as more than two days and up to two weeks. Condensate should be completely drained from the shell side. Water side circulation should be continuous, or at least one half-hour per day for wet lay-up. For dry lay-up, the waterboxes and tubes should be completely drained and inspected visually. Any tube found plugged with debris should be cleaned by shooting scrapers or brushes. After tube cleaning, waterbox, tubesheet, and tube internal surfaces should be flushed with potable water. This can be done quickly by using a fire hose and spending at least ten seconds on each group of tubes.

x

Long-term is defined as longer than two weeks. The shell side should be drained of all condensate, as in the medium-term lay-up. All isolated pools of water should be dried by using sponges or mops. Also consider circulating air through the shell with blowers. Airflow should be monitored for temperature and humidity every few days and flow should be adjusted to achieve non-condensing conditions.

8.3.4 Design Modifications Erosion-corrosion can occur in the waterbox, tubesheet, and inlet tube areas because of turbulence in the inlet flow. Any modifications to the waterbox and tubesheet inlet might have to be removed for tube cleaning. The addition of baffles and screens might influence any cathodic protection that is installed. Figure 8-7 shows a venturi effect from the inlet pipe being a smaller diameter than the inlet nozzle.

8-27


Figure 8-7 Air Bubble Turbulence in a Low-Pressure Zone [27]

Figure 8-8(a) shows a poor design inlet causing turbulence in the waterbox. Figure 8-8(b) shows a perforated baffle plate as an improvement to this design.

8-28


Figure 8-8 (a) Poor Design for Tube Inlet Flow [27] (b) Improved Design with Perforated Baffle Plate [27]

8-29


Figure 8-9(a) shows another poor design inlet area to the waterbox with a baffle plate to divide the flow. Figure 8-9(b) shows an improved design with a screen installed to direct the water flow.

Figure 8-9 (a) Poor Design Tubesheet Inlet [27] (b) Improved Design with Screen [27]

8-30


The addition of vanes to direct the flow to reduce turbulence downstream (particularly in the inlet region) is frequently effective in reducing incidences of erosion-corrosion.

8-31


9 CONDITION-BASED MAINTENANCE [4,10]

A comprehensive condition-based maintenance program for a condenser consists of the following elements: x

Maintenance of good records

x

Periodic inspections

x

Preventive maintenance activities

x

Non-destructive examination (NDE)

9.1

Records

Records of tube plugging and other maintenance activities provide useful information regarding the condition of the condenser. These records should include a drawing of each tubesheet showing the plugged tubes and the date of plugging. Each tube in the condenser should be numbered and all information recorded, including NDE testing results and failure analysis filed by the tube number.

9.2

Periodic Inspections

Visual examination of the water side of the condenser includes the waterboxes, tubesheets, and tube ends. Shell side inspection includes the exterior shell, nozzles, and the interior shell, peripheral tubes, peripheral support plates, structural components, spargers, baffles, turbine/condenser expansion joints, and hotwell. When conducting a visual examination, note the locations in the tube bundle where corrosion is occurring. This might provide an indication of the causes of corrosion. A borescope can be used for the internal inspection of many components. The following are some guidelines for visual inspection of the various condenser components. 9.2.1 Waterbox Cast-iron waterboxes are subject to graphitization. A fairly smooth graphite layer indicates the original waterbox surface. Probing with a chisel will show the depth of the affected area. If there is no reason to suspect only local occurrences of graphitization, a uniform corrosion over the entire surface should be assumed. Carbon steel waterboxes should be carefully inspected for signs of galvanic corrosion.

9-1

EPRI Licensed Material Condition-Based Maintenance [4,10]

Waterbox inspections should be performed during each refueling outage and include the following inspection tasks: x

Visual inspection for evidence of erosion, corrosion, and cracks

x

Visual inspection for fouling and determination of the degree of fouling for future cleaning intervals

x

Inspection of the cathodic protection system for damage to anodes and supports; ensuring proper settings and operation of the impressed and sacrificial systems

x

Inspection of o-rings for evidence of damage and deterioration

x

Examination of the welds on the waterbox platform and the ladder rungs for any failure

9.2.2 Tubesheet Tubesheet visual inspections should be performed with the waterbox inspections every refueling outage. The following should be included in the tubesheet inspections: x

Verification of the tube plugging map

x

Examination of the tube plugs for integrity

x

Inspection of coatings on the tubesheet

x

Performance of pressure leak testing to identify tube leaks

x

Ligament cracks between tubesheet holes

x

Tubercular deposits around tube joints

x

Distortions

x

Excessive tube extrusion or recession

x

Corrosive deterioration near the waterbox

x

Discolorations due to dealloying

x

Crevice corrosion

x

Galvanic corrosion

x

Tube inlet-end corrosion on copper-alloy tubes due to high turbulence in this region. Observe the surface condition of the tube inlet. If deterioration is detected by touch, a photographic record is suggested. If scales are noticed on the tube outlet ends, bore measurements should be recorded with a bore gage before and after cleaning.

x

Borescope examination on a representative sample of tubes. A borescope inspection is the visual examination of the inside diameter of the tubes using a rod with a fiber-optic cable and lens. The rod is inserted in the tube and indications are noted at each increment length inside the tube. It is possible to record these images using a specialized camera.

9-2


9.2.3 Hotwell Hotwell inspections should be performed during each refueling outage with the waterbox inspections. The inspection should include the following: x

Visual inspection for foreign materials and general cleanliness.

x

Inspection for erosion, corrosion, cracks, and weld failures of all internals.

x

Inspection for cracking in the tube support welds, sparger lines, and impingement plates.

x

Visual inspection for evidence of steam/fluid erosion.

x

Inspection of the condensate pit screening for looseness.

x

Inspection of the baffles for cracks and evidence of failure.

x

Examination of the internal baffles and spargers for weld cracks and ligament cracks.

x

Inspect the turbine expansion joint and protective cover for cracks, damage, and overall condition.

x

Inspect the extraction steam piping expansion joints and protective cover for cracks, damage, and overall condition.

9.2.4 Tube Bundles Inspection of the tube bundles from the steam side of the condenser should be performed with the hotwell inspection during each refueling outage. The inspection should include the following: x

Inspection for loose, damaged, and missing tube stakes.

x

Inspection of the tube bundles for erosion-corrosion from direct impingement of steam from the spargers.

x

Inspection of outside tubes for erosion, tube vibration, flattening of the support plate, and general signs of fatigue.

x

Support plate examination is usually limited to the periphery of the tube bundle. Distortion might be apparent. If distortion is suspected, alignment should be checked by stretching a string through a set of holes. This will require extraction of a peripheral tube and subsequent plugging of tubesheet holes.

x

Inspect flows diverted from various baffled drain connections for damage on the tubes.

9.2.5 Structural Components The following structural components of the condenser should be visually inspected during each refueling outage: x

Inspect the condition of the air off-take piping on the inlet end of the condenser for corrosion.

x

Inspect the condenser shell for any cracks at seams or penetrations. The condenser shell is typically a mild carbon steel plate. Use a wire brush, if required, to reveal cracks. NDE 9-3


methods can be used to confirm suspected cracks. The internal shell is also susceptible to uniform corrosion and erosion-corrosion. Because the oxygen content is low inside the shell, corrosion rates will be relatively slow. However, any indication of shell erosion-corrosion should be recorded. x

Components such as flanges, channels, and pipe supports should be examined for distortion and erosion.

x

Examine the neck heaters and piping for any damaged or removed lagging.

9.3

Preventive Maintenance (PM) [10]

All main condensers are considered critical equipment, have a high duty cycle, and experience severe service conditions. Critical equipment is defined as equipment required for power production. High duty cycle implies continuous operation and severe service conditions. Severe service conditions include temperature cycling, water chemistry problems, tube vibration, and poor quality of the cooling medium. 9.3.1 Cleaning Key Technical Point Cleaning by mechanical and/or chemical techniques is the only preventive task that prevents corrosion or slows its progression, maintains tube reliability, and extends the life of the tubes. If cleaning is not performed regularly as determined from plant experience, fouling and scaling advance to the point where they become essentially unmanageable and physically difficult to remove. The recommended interval is as required because the appropriate schedule is very dependent on local conditions. The interval is less than two years for a significant fraction of plants but might be longer in some cases. Cleaning should include an evaluation of the type and degree of performance degradation and type of fouling. The next step would be to determine the appropriate cleaning method that provides the best results and limits damage to the condenser materials including heat transfer surfaces, tubesheets, tube plugs, tube sleeves, waterbox, piping, and valves. The currently available options include mechanical devices (metal scrapers, plastic scrapers, and nylon brushes), hydrolasing, chemical cleaning, and on-line cleaning (sponge ball systems and cage and brush). More information on mechanical and chemical cleaning can be found in Section 6. 9.3.2 Performance Monitoring Performance monitoring includes the determination of the cleanliness factor, heat transfer abilities, condenser backpressure, thermal efficiencies, and so on. More discussion on condenser performance is found in Section 4.

9-4


Performance monitoring every week is recommended to address the vulnerability to sudden onset and propagation of corrosion and fouling. Performance monitoring should include the following: x

Monitor, track, and trend tube pressure difference

x

Monitor, track, and trend tube temperature difference

x

Monitor impressed cathodic protection settings and performance

x

Monitor, track, and trend condenser cleanliness factor

x

Sample fluids for the presence of cross-contamination and trend

x

Monitor, track, and trend turbine backpressure

x

Monitor and trend air in-leakage levels

9.3.3 Operator Rounds Operator rounds are included as a PM task that is performed continuously. Operator rounds might include activities such as detecting external leaks, monitoring operational parameters such as 'T and 'P, turbine backpressure, and air-removal rate. 9.3.4 Preventive Maintenance Summary Tables Based on the duty cycle and service conditions, EPRI developed a list of failure locations, degradation mechanisms, and corresponding preventive maintenance strategies. This is shown in Table 9-1. The components evaluated include the tubes, tube-to-tubesheet joints, waterbox, tubesheet, hotwell expansion joint, and hotwell. PM tasks to prevent the degradation mechanisms, and the corresponding task interval, were developed and are listed in Table 9-2. The PM tasks include performance monitoring, NDE inspection, hotwell inspections, waterbox inspection, cleaning, and operator rounds. NDE inspections include the use of eddy current testing, ultrasonic testing, and borescope inspections. More details on NDE testing are given in Section 9.4. Chemistry monitoring, chemical treatment, and cathodic protection are considered important but routine activities in the operation and maintenance of the condenser.

9-5

9-6

Failure Location Tubes

-Fluid quality -Internal tube condition -Water temperature range 60q to 90qF (15q to 32qC) -Water chemistry -Low flow rates (including lay-up) -Tube material -Improperly designed or operated cathodic protection -Tube manufacturer (for example, discontinuities and welds) -Improper tube cleaning

Corrosion MIC

Erosion (external)

Degradation Influence -High flow velocity -Suspended solids -Foreign material -Flow accelerated corrosion -Non-uniform scale deposits -Steam impingement -Foreign material -Fluid impingement

Degradation Mechanism Erosion (internal)

-Random

-Continuous

-Random

-Continuous

-Continuous -Random

-Continuous -Random -Continuous

-Random -Continuous

Degradation Progression -Continuous

Failure Timing -Random on a scale of months to many years -Random -Random on a scale of months to many years -Random, could be very rapid -Random -Random, could be very rapid Random, can be rapid

Table 9-1 Failure Locations, Degradation Mechanisms, and PM Strategies [10]

Condition-Based Maintenance [4,10]


-Inspection - 'T -Heat transfer -Chemistry monitoring(Unexplained changes in water chemistry total organic content, conductivity, pH, elemental composition) -Eddy current -Cleaning -Leak testing (trace gas) -Chemical treatment

-Eddy current -Inspection -Chemistry monitoring -Leak testing (trace gas)

Discovery/Prevention Opportunity -Eddy current -Inspection -Cleaning -Chemistry monitoring -Leak testing (trace gas)

-Waterbox inspection -Cleaning -Performance monitoring -NDE inspection

-NDE inspection -Hotwell inspection -Waterbox inspection

-NDE inspection -Cleaning -Waterbox inspection

PM Strategy

Tubes, cont.

Failure Location

-Manufacturing defect -Installation error -Vibration

Defect

Cracking

Microbiological fouling

-Water chemistry -Tube material -Improper cathodic protection -Tubesheet material

Corrosion -Galvanic

-Improper chemical treatment -Temperature -Low flow velocity -Environmental -Water quality

-Fatigue -Improper tube staking -Inappropriate tube cleaning

-Water chemistry -Water temperature -Tube material -Internal tube condition

Degradation Influence

Corrosion -Chemical

Degradation Mechanism

-Continuous

-Random

Continuous or Random

Random

Continuous

Continuous

Degradation Progression Failure Timing

Random on a scale of a week to several months

Random

Random

Expect to be failure-free for a few months

Random on a scale of weeks to months

Table 9-1 (cont.) Failure Locations, Degradation Mechanisms, and PM Strategies [10]


-Turbine backpressure -Chemistry monitoring -Inspection -'P/'T -Cleaning -Heat transfer -Chemical treatment

-Inspection -Chemistry monitoring -Eddy current -Cleaning -Leak testing (trace gas) -Chemical treatment -Inspection -Chemistry monitoring -Eddy current -Cleaning -Cathodic protection -Leak testing (trace gas) -Chemical treatment -Inspection -Eddy current -Leak testing (trace gas) -Eddy current -Inspection -Leak testing -Chemistry monitoring

Discovery/Prevention Opportunity

9-7

- Waterbox inspection -Operator rounds -Performance monitoring -Cleaning

-NDE inspection -Waterbox inspection -NDE inspection -Hotwell inspection

-NDE inspection -Cleaning -Waterbox inspection

-Waterbox inspection -NDE inspection -Cleaning

PM Strategy


9-8

Tube JointWelded

Failure Location Tubes, cont.

-Improper installation -Improper plugging

-Random

-Improper chemical treatment -Temperature -Low flow velocity -Environmental -Water quality -Inappropriate tube cleaning -Personnel error

Mechanical damage Defect

-Continuous

-Sand/silt

Scaling or deposit

-Random

-Random

-Continuous

-Continuous

Degradation Progression -Random

Degradation Influence -Debris, for example, clam shells, fish, rocks, other foreign material and marine debris -Zebra mussels -Sand/silt

Degradation Mechanism Macrofouling

Failure Timing

-Random

-Random

-Random on a scale of 3 to 6 months

-Random, can be rapid -Random, depends on conditions -Random, depends on conditions

-Random




-Chemistry monitoring -Ultrasonic leak testing -Pressure testing

-Inspection

-Turbine backpressure -'P/'T -Inspection -Cleaning -Heat transfer -Chemical treatment

Discovery/Prevention Opportunity -Turbine backpressure -'P/'T -Inspection -Cleaning -Heat transfer -Chemical treatment

-Waterbox inspection

-Hotwell inspection

-Operator rounds -Performance monitoring -Cleaning -Waterbox inspection

-Operator rounds -Performance monitoring -Cleaning -Waterbox inspection

PM Strategy

Tubesheet

Waterbox, Manways, Expansion Seals, Welds, and Liner

Defect

Tube JointRolled

Cracking of ligaments

Corrosion

-Mechanical damage to liner -Failed welds

-General corrosion -Elastomer aging/wear

Galvanic attack


Failure Location

-Improper cathodic protection -Water chemistry -Materials -Improper plugging

-Improper or failed cathodic protection -Improper maintenance -Aging (elastomer)

-Improper cleaning technique -Improper installation -Improper plugging -Water chemistry -Materials inspection -Improper cathodic protection -Water quality


-Random

-Continuous

-Random

-Expect to be failure-free for about 5 years (depends on usage and manufacturer) -Random on a scale of months to years

-Random

-Random -Continuous

-Expect to be failure-free for many years

-Random

-Random

Failure Timing

-Continuous

-Continuous

-Random

Degradation Progression



-Inspection

-Cathodic protection -Inspection

-Inspection

-Inspection -Cathodic protection

-Chemistry monitoring -Ultrasonic leak testing -Pressure testing




9-9

-Waterbox inspection -Operator rounds



PM Strategy


-Design defect

-Excessive operational stress -Design defect

-Steam erosion

-Cracking of welds

9-10

-Vibration

-Cracking of welds

Hotwell: Tube Support Plates, Support Hardware, Baffle Plates, Diffuser Shields and Feedwater Heater Supports Penetration Baffles -Continuous

-Random

-Continuous

-Continuous

-Continuous

-Random

-Improper installation -Improper plugging -Improper cleaning -Manufacturing defect -Vibration

Cracking

-Continuous

Aging

Elastomer failure, if present Defect

-Continuous

Degradation Progression

Flow-induced vibration


Cracked shield plate


Hotwell: Penetration Baffles and Spray Pipes

Hotwell: Expansion Joint

Failure Location

Failure Timing

-Random, could be rapid

-Expect to be failure-free for many years -Expect to be failure-free for many years

-Random -Expect to be failure-free for many years

Expect to be failure-free for several years Expect to be failure-free for several years -Random




-Inspection -Chemistry monitoring

-Inspection

-Chemistry monitoring -Pressure test -Ultrasonic test -Inspection -Leak testing -Turbine backpressure -Air-removal rate -Air binding -Inspection

-Inspection

-Inspection


-Hotwell inspection

-Hotwell inspection

-Hotwell inspection

-Hotwell inspection -Operator rounds


-Hotwell inspection

-Hotwell inspection

PM Strategy

Failure Location Tubes

Random on a scale of months to years Random, could be very rapid Random, could be very rapid Random on a scale of weeks to months Expect to be failure-free for a few months Random Random Random on a scale of a week to several months Random, can be rapid

Failure Timing

X X X

X

Defect Cracking Microbiological fouling Macrofouling

X

X

X X X

X

X

X

X

X

X

X

X

X

X

X

As Required

Cleaning

X

X

9-11

Operator Rounds Shift


Waterbox Inspection 2 Years

X

X

Hotwell Inspection 2 Years

X

X

X

NDE Inspection 2 Years

X

X

Performance Monitoring 1 Week

Corrosion (Galvanic)

Erosion (external) Corrosion (MIC) Corrosion (Chemical)

Interval Degradation Mechanism Erosion (internal)

PM Task

Table 9-2 PM Tasks and Their Degradation Mechanisms [10]


Expect to be failurefree for several years

Hotwell: Expansion Joint

9-12

Random, on a scale of months to years Random

Random

Random Expect to be failurefree for about five years, depends on usage and manufacturer Expect to be failurefree for many years

Random

Random

Random, depends on conditions, can be three to six months Random

Failure Timing

Tubesheet

Waterbox Manway, Expansion Seal, Welds and Liner

Tube Joint: Welded Tube Joint: Rolled

Tube OD

Failure Location Tubes, cont.

Cracking of ligaments - Cracked shield plate - Elastomer failure, if present

- Corrosion - Elastomer aging Mechanical damage to liner Corrosion

Galvanic attack Defect Failed welds

Mechanical damage Defect

Interval Degradation Mechanism Scaling or deposit

PM Task

X


Table 9-2 (cont.) PM Tasks and Their Degradation Mechanisms [10]


NDE Inspection 2 Years


X

X


X

X

X

X

X X

X

X

X

Waterbox Inspection 2 Years

X

As Required

Cleaning

X

X

X

X


Failure Location Hotwell: Penetration Baffles and Spray Pipes Hotwell: Tube Support Plates and Hardware, Baffle Plates, Diffuser Shields, Feedwater Heater Supports Penetration Baffles - Cracking of welds; - Steam erosion

Cracking of welds

Random, could be rapid

Interval Degradation Mechanism Cracking

Expect to be failurefree for many years

Expect to be failurefree for many years, some random

Failure Timing

PM Task


Table 9-2 (cont.) PM Tasks and Their Degradation Mechanisms [10] NDE Inspection 2 Years


X

X


X

Waterbox Inspection 2 Years As Required

Cleaning

X

9-13




9.4

Non-Destructive Examination (NDE) [4]

NDE consists of a large number of complex physical methods and procedures, designed to harmlessly test and evaluate the adequacy of a component, part, or a system. While NDE procedures might or might not be non-invasive, they are always indirect assessments obtained by correlating the measured property with the reference standards. NDE testing is primarily a material condition assessment and the information it provides is predictive of future deterioration. It is beneficial to perform the task each outage to provide a continuous assessment of condition. Substantial technical knowledge, skill, experience, and informed judgment are essential for the successful application of NDE. Among the NDE methods available, the following methods are classified as major ones for use on the condenser: x

Magnetic particle (MT)

x

Liquid penetrant (PT)

x

Ultrasonic (UT)

x

Visual (VT) – discussed in Section 9.2

x

Eddy Current (ET)

9.4.1 Magnetic Particle Testing (MT) This method is used for detection of surface or shallow sub-surface flaws in magnetic materials (cracks, forging laps, non-metallic inclusions). Its comparative advantage over other surface test methods is that it is fast and the surface need not be smooth and clean. This method is not applicable to non-ferrous metals or alloys. In this method, a magnetic flux is induced in ferromagnetic material. Any abrupt discontinuity in the path of the flux creates local flux leakage. If finely divided particles of ferromagnetic material are brought into the vicinity, they will collect around the defect. Color contrast (observed visually) or fluorescent magnetic particles observed under black light can be applied dry or suspended in a petroleum distillate. 9.4.2 Liquid Penetrant Testing (PT) This method is strictly a surface inspection method. The method operates on the principle that an open surface flaw will absorb liquid colored dye by capillary action. Liquid dye is applied to a suspect surface and, after a soaking period of approximately 10 minutes, the surface is thoroughly cleaned and dried. A developer chemical is then lightly sprayed on the surface. The developer draws the dye out of the defect, clearly outlining the flaw. This method can be applied to magnetic or non-magnetic materials. The tested surface must be thoroughly clean and smooth.

9-14


9.4.3 Ultrasonic Testing (UT) This method employs high frequency mechanical vibration energy to detect structural discontinuities and to measure the thickness of a variety of materials. Transmitted and reflected sound energy is converted to electrical energy by a transducer. The signal received can be displayed on a cathode-ray tube to indicate conditions of the test object. UT can be used to identify weld defects, cracks, and so on. Ultrasonic testing is used to measure the thickness of tubesheets for wear. 9.4.4 Eddy Current Testing (ET) [30] Eddy current testing on condenser tubes can reduce maintenance costs by minimizing tube leaks and by establishing realistic plugging criteria. The availability of condensers is increased with ET by extending the examination intervals and reducing the application of insurance plugs. A realistic assessment of condenser condition can be provided by ET. This includes determining the number of degraded tubes, predicting the growth rate of current tube damage, and estimating the remaining operating life of the tube bundles. ET is the technique used to locate or avoid future tube leaks. The technique allows a determination of whether condenser tubes have become pitted, corroded, or cracked. It also provides an estimate of the depth of such blemishes, their angular location and distance along the length of the tube. Key Technical Point ET is a non-destructive test technique that causes electrical currents to be induced in the material being tested. The associated magnetic flux distribution within the material is then observed. Because the results from eddy current testing can be affected by a number of factors, successful eddy current testing requires a high level of operator training and awareness. Eddy current testing is based on a correlation between electro-magnetic properties and physical properties of a test object. Eddy currents are induced in metals whenever they are brought into an alternating current (AC) magnetic field. In test samples, eddy currents are generated by placing an AC coil in close proximity to the surface to be tested. These eddy currents create a secondary magnetic field that opposes the inducing magnetic field of the coil, thus changing the coil impedance. If a coil is drawn through a tube (Figure 9-1) or over a surface, the presence of discontinuities will alter the eddy current and the coil impedance, identifying the location of the fault.

9-15


Figure 9-1 ET Probe for Condenser Tube Testing [4]

ET is a surface and a volumetric testing technique for tubing. Penetration of eddy currents is limited by material conductivity and AC frequency. As depth increases, the penetration of eddy current decreases. Key Technical Point Eddy current instruments and recording instruments have a limited frequency response, that is, they require a certain time to respond to an input signal. Therefore, pulling an ET probe through a tube at a high speed will result in poor examination. Most testing should be performed at probe speeds of 60 to 120 feet per minute (18.3 to 36.6 meters/minute).

Key Technical Point It is recommended that the tubes be cleaned before performing ET. By bringing the tubes to a clean state, the possible effects on the electromagnetic flux distribution of any deposits present will be minimized. Also, obstructed tubes should be cleared so that the ET probe can pass through. When starting with clean tubes, data from one test can be compared to another. Before testing the condenser tubes, the ET system must first be calibrated using a sample of the same tube material. Probes are usually either of the bobbin- or surface-type. For best results, the effective diameter of the probe should be close to that of the inside diameter of the tube, with allowance being made for tube manufacturing tolerances.

9-16


The information obtained from ET conducted at several points in time can also help in scheduling maintenance and planning a tube replacement or plugging strategy. This is important for extending tube life of the condenser and avoiding unscheduled unit outages. In the eddy current testing of condenser tubes, there are at least four kinds of damage that might be detected: x

Corrosion pitting

x

Tube outside diameter steam erosion (grooving)

x

Fractures and wall thinning caused by tube vibration (denting)

x

Near through-wall penetrations

x

Blocked tubes (found when ET probe cannot pass through)

In the first three, the depth of penetration is an important benchmark, influencing a decision whether to plug the tube as a precaution against future leaks. The identification of near throughwall leaks will require tube plugging when all of the testing has been completed. Blocked tubes should be detected if the tubes are cleaned prior to ET. Advantages of eddy current testing are: x

High examination rate

x

Permanent records of tube condition are created for later comparison

x

Reasonable accuracy

Disadvantages of eddy current testing are: x

Sophisticated and relatively expensive equipment

x

Accuracy is heavily dependent on operator skill

9.4.4.1

Planning the Eddy Current Test

The method of performing a planned test must be carefully specified. Data trending and evaluation are also important parts of the overall project. In this way, the results of each test can be compared and sound judgements can be made regarding the effects of different maintenance methods, as well as the rate of tube deterioration. Part of the planning process involves: x

Writing well thought through eddy current test procedures for the whole set of annual or periodic tests

x

Insisting that the tests be conducted in exactly the same way for each inspection

9-17


x

Making use of the same calibration pieces and the same type of equipment for each test

x

Employing only operators who have each been subjected to the same training and qualification requirements such as the ASME Boiler and Pressure Vessel Code, Section V, Appendix 8 - ASNT SNT-TC-1A Key Human Performance Point Where the bidding process might result in a different contractor being employed for each inspection, the necessity for a common procedure ensures that eddy current data from one inspection can be compared with confidence to the data from inspections conducted in prior years. Without such formal procedures and owner supervision, reliable data trending is virtually impossible.

It might be said that firm adherence to established procedures tends to inhibit technological advances. It is true that advances might be introduced more gradually. The absolute values obtained from eddy current testing are important in determining the damage mechanism and the appropriate corrective action to be taken. The ability to determine the rate of change of corrosion is very important concerning planning when, or if, retubing is needed. 9.4.4.2

Tube Map

A whole tube map should be defined prior to the first inspection, and the same tube numbering should be used for all future examinations and maintained throughout the life of the unit. The configuration of this map should be well controlled and changes made only in a very orderly fashion. Tubes that have been plugged should be clearly identified. At each inspection, the previously installed plugs should be checked to make sure they are still in place. 9.4.4.3

Benchmark Data Set

It is important to have a benchmark ET data set for the condenser tubes. Preferably, this should be taken before the unit is first started up. This is a baseline for which future changes can be compared. The eddy current calibration tube should be taken from the same manufacturing batch as the tubes installed in the unit. The calibration standards should be stored in a known place and used for each subsequent examination of the condenser. 9.4.4.4

Data Comparisons and Trending

The program used to analyze the data need not be extremely sophisticated. For example, some users have written their own BASIC language program having about 2400 lines of BASIC code. The data for each inspection should be contained on a separate disk so that each inspection can be analyzed independently. In the comparing mode, the data from several inspections should be able to be read in, one set at a time, processed, and then compared. The creation of tube maps can be performed for one set of inspection data at a time. The plotting program can be separate from the analytical program, if it is written to accept the same data file 9-18


layout and format. The comparison of data sets, or trending, is made easier if 100% of the tubes are inspected every time. However, if only a subset of tubes is to be examined, this procedure requires more careful planning to ensure a high level of data continuity from one inspection to another. 9.4.4.5

Maintenance Practices

In order that changes in corrosion rate be correlated with procedural changes, it is important to log all changes in maintenance practice as they occur. For example, at one site, mechanical cleaning was identified as the cause of the reduced corrosion rate. Changes in water treatment practice should also be logged, and a summary of all of these changes provided to the inspector before a new eddy current inspection is performed. 9.4.4.6

Figures of Merit Key Human Performance Point The term figures of merit as used in the analysis of eddy current tests is the generic name applied to various criteria used to compare test results. Figures of merit have different criteria in the case of a condenser compared with those for a heat exchanger. With heat exchangers, considerations of meeting the Pressure Vessel Code override questions of mere wall penetration. In any given plant, there should be some agreement on how corrosion figures of merit will be defined when evaluating eddy current test results.

Some condenser users have chosen as a figure of merit the mean annual corrosion rate and have used this to predict when a condenser should be retubed. Figures of merit can also be used as tube plugging criteria although, as the number of plugged tubes increases, the reduced capacity of the condenser to remove latent heat must be considered. 9.4.4.7

Management Report

It is a common complaint that eddy current test reports are so full of detailed data that it is difficult for management to appraise the results and make appropriate decisions. For this reason, it is recommended that a summary, or executive report, be provided so that management can understand the significance of the results within the carefully structured long-term plan. 9.4.4.8

Pre-Outage Activities

Pre-outage planning is important for a successful ET examination. The following tasks need to be completed for the planning phase of the process: 1. Gather condenser design, operating, chemistry, and prior ET exam data. Any abnormal operating history, chemistry incursions, known problems, etc. should be reviewed. Obtaining the last set of ET results is needed for comparison.

9-19


2. Establish the tube-sampling scheme consistent with the existing numbering system. An important consideration for selecting an inspection sample is the expected or known damage mechanisms based on past inspection results or repair records. This generally includes targeting those tubes with degraded indications and tubes surrounding the already plugged or leaking tubes. It is also desirable to include a sample of tubes for detection of any new problems. The selected percentage varies but typically will be in the range of 10-30%. The combined sampling scheme of targeted and random sampling should equal around 40% of the total number of tubes. Expanding the sample is appropriate when a problem is detected. The expanded inspection is typically performed by bounding the problem until the surrounding tubes no longer exhibit degraded flaw conditions. 3. Establish tube plugging criteria – The current plugging criteria for condensers varies from plant to plant and is based on percent wall losses, that is, 40 to 80% wall losses. The tube plugging criteria in percent wall loss is equated to allowable wall loss minus eddy current sizing error. Currently, the allowable wall loss in percent wall loss is derived from the following weighted average of ten tube wall degradation factors: 1. Consequence of leakage 2. Safety-related equipment 3. Type of damage mechanism 4. Flaw growth rate 5. Tube material type 6. Available leak detection method 7. Condition of water chemistry 8. Fouling potential 9. Design pressure 10. Design temperature Key Technical Point Depending on the degradation factor, the allowable wall loss can be in the range of 50-90 percent wall loss. Consequently, if the eddy current sizing error of 10 percent is used, the resultant plugging criteria can be 40-80 percent wall loss. 4. Prepare bid specifications 5. Prepare for tube cleaning/repair/remedial measures 6. Vendor selection 7. Vendor performance demonstration test 8. Qualify eddy current data acquisition/analysis procedures and data analysts

9-20


9.4.4.9

Outage Activities

The on-site eddy current examination activities include the following components: x

Obtain personnel certification and equipment calibration records

x

Prepare, visually inspect, and clean tubes as necessary

x

Implement eddy current examination plan

x

Obtain daily status of examination results

x

Use database management program to monitor progress

9.4.4.10

Post-Outage Activities

The post-eddy current examination activities include the following components: x

Perform root cause analysis as required

x

Conduct vendor exit interview to include a listing and tubesheet map of the plugged, degraded, and defective tubes and a final examination report

The final step in the process is to monitor and trend the final activities and make final recommendations to management. 9.4.4.11

ET Flowchart

Figure 9-2 shows the important features of an effective eddy current condenser inspection process in a flowchart format.

9-21


Figure 9-2 ET Flowchart [30]

9-22


10 MAINTENANCE REPAIRS [3]

There are numerous repairs that might be necessary to perform on condensers. Some of the types of repairs are: x

Plugging tubes

x

Installation of tube inserts or shields to protect the tube inlet/outlet from erosion/corrosion or to repair a degraded tube region

x

Installation of sleeves for structural repair of degraded tube regions

x

Coating of the tube ends to prevent erosion/corrosion

x

Lining the tube to protect against thinning/erosion/corrosion

x

Coating the full-length of the tube for protection against thinning/erosion/corrosion

x

Re-expanding the tube-to-tubesheet joints to prevent leaks

x

Coating of the tubesheets to protect from corrosion

x

Retubing – see Section 11

x

Tube staking for vibration

x

Waterbox repairs

x

Tubesheet repairs

x

Tube pulling

x

Miscellaneous repairs

10.1 Plugging Tubes [24] Biodegradable leak stops, typically sawdust, have been injected into utility condensers for decades to provide temporary plugging/stopping of a small leak or leaks. The leak stop material is dumped into the intake bays immediately upstream of the circulating water pumps. Sawdust in the circulating water flow fills and lodges in condenser tube holes temporarily preventing leakage. Sawdust is continuously injected into the system until the hotwell cation conductivity reading returns to normal. When the leak stops, the need for hotwell blowdown/makeup and/or use of the condensate polishing demineralizers will significantly reduce. A subsequent rise in cation conductivity indicates the need for plugging, repair, or additional injection of sawdust. Despite injection frequency, continued use of sawdust is a very clear indication of the necessity to perform a condition assessment and life prediction analysis. Once sawdust is used, it is certain 10-1

EPRI Licensed Material Maintenance Repairs [3]

that chronic tube leaks will persist and ultimately will become so severe that sawdust injection will become an ineffective control agent. The tube failure rate at that time will become very significant, sometimes too high to prevent a forced outage or multiple recurring forced outages. Once a leaking tube has been detected, it is usually necessary to plug the tube. There is typically excess surface area in the condenser design to allow as many as 10% of the tubes to be plugged without reducing the effective heat transfer capacity of the unit. Plugging is also performed from eddy current test results on tubes that have the potential to leak before the next inspection. Selection of a tube plug is based on experience with a particular application and a preference for a specific plug design. Numerous plugging methods are available depending on the tube material and damage forms. The following are guidelines for tube plugging. 10.1.1 Preparation for Tube Plugging [31] At a minimum, the following requirements should be adhered to in preparation for plugging tubes: 1. The tubes to be plugged should be located and clearly identified. Both ends of the same tube should be clearly marked. A common problem observed during leak testing is the marking of the leaking tube on one tubesheet and incorrectly marking the tube on the other end of the tubesheet. Several ways to ensure that both ends of the same leaking tube are marked correctly include using a laser pointer, a flexible probe or rod, air flow, and so on. 2. Tubes to be plugged should be cleaned as necessary to ensure a proper seal between the plug and tube and/or tubesheet. 3. A plugging procedure should be made available for review and approval. 4. If welded plugs are used, the weld procedure should give consideration to adequate pre-heat and post-weld stress relieving. Warping of the tubesheet and damage to adjacent tube joints can occur if the proper stress relieving is not performed. 5. If necessary, stabilize the failed tube to prevent additional damage to neighboring tubes. This can be accomplished by inserting a rod or cable into the tube to provide additional internal support. The rod or cable should be long enough to bridge the defective region of the tube and reach through the next support plate. One end of the stabilizer should be anchored to the tube and/or tubesheet to prevent migration within the tube during condenser operation. Tube stabilizers can be fabricated on site or purchased commercially. Unless the stabilizer is an integral part of one of the tube plugs, both ends of the tube should be plugged after installing the stabilizer. 6. After the plugging operation, leak testing of the plugged tubes is recommended.

10-2


10.1.2 Tube Plug Selection [3] There are many different types of condenser tube plugs from which to choose. Consider the following requirements when selecting tube plugs: x

The plug should be permanent and leak-tight for the life of the condenser. At the same time, the plug should be easily removable for retubing.

x

The plug installation process should be controllable and the action of installing the plug should not damage the tube, tubesheet ligaments, tube joints, or the epoxy coating applied to the tubesheet and/or tube.

x

The plug itself should be constructed of materials that are rated for an infinite life of continuous duty in the condenser environment. The plug materials should resist any corrosion and aging effects that might cause leakage.

x

The ideal condenser plug should not require periodic re-tightening and inspection to verify that they are leak-tight.

x

The plug should resist pressure from either direction. Key O&M Cost Point In situations where previously installed plugs are missing, leaking, or have caused collateral damage to the tube and tubesheet, the actual plug cost should not be a major factor. The expense associated with controlling persistent water in-leakage as a result of tube and plug leaks can be many times the cost of even the most expensive plug.

10.1.3 Tube Plug Types [4] Plug designs can be categorized as: x

Hammer-in taper type

x

Elastomer type

x

Mechanical type

x

Welded type

10.1.3.1

Hammer-In Taper Plugs

Hammer-in taper plugs are conical-shaped plugs that are driven into the tube end using a hammer. These plugs are easily fabricated on site or are available from a number of commercial sources. Plug materials include wood, plant fiber and metal alloys. Consideration should be given to plug material selection in order to prevent galvanic corrosion. The simplest taper plugs are made of wood. Wood is a slightly compressible material that makes a good fit when driven into the tube with a hammer. The plug swells when wet and the swelling makes a tight fit. Some examples of tapered plugs are shown in Figure 10-1. 10-3


Figure 10-1 Assorted Hammer-In Taper Plugs (courtesy of MGT, Inc., Boulder, CO)

The taper plugs can have an included angle of between 3 and 8 degrees. They are designed for an interference fit between the plug and the tube end and also the tube end and the tubesheet. The intention is to drive the plug hard enough to close both the tube leak and any tube joint leak. Some disadvantages of using the tapered plug include: x

Plugs might damage tubesheet hole, making it difficult to retube.

x

Eroded tube inlets might prevent proper sealing.

x

Excessive force might result in ligament cracks in the tubesheet.

x

Inadequate force might result in the plug coming loose.

x

During an outage, the fiber and wood plugs might dry out, shrink and loosen.

x

Dissimilar metal plugs might induce galvanic corrosion.

x

Use of these plugs is not advisable where coatings have been applied to the tube end or tubesheet.

x

These plugs are difficult to remove for tube replacement. Some hammer-in taper plugs are manufactured with a drilled and tapered hole on the large diameter end to improve removability.

x

These plugs have low seal integrity.

Two-piece hammer-in plugs employ a conical-shaped pin that fits into an outer sealing ring. An example of this style plug is shown in Figure 10-2.

10-4


Figure 10-2 Two-Piece Hammer-In Plug (courtesy of Elliott Tool Technologies, Dayton, OH)

Plug installation is accomplished by using a hammer to drive the smaller end of the pin into the ring so that the ring expands outward to seal against the tube wall. The greater surface area of the ring distributes the installation forces over a greater area of the tube, thereby reducing collateral damage to the tube, tube joint, and tubesheet. Two-piece hammer-in plugs are commercially available in a number of metal alloy materials. Consideration should be given to plug material selection in order to prevent galvanic corrosion. When this plug is properly installed it provides a moderate seal integrity. Limitations of the design include the following: x

The smooth outer surface of the sealing ring is not able to conform to minor tube defects caused by erosion and corrosion.

x

The high plug installation forces might cause collateral damage to the tube end, tube joints, and/or tubesheet.

x

Two-piece hammer-in plugs should not be used in applications with coated tubes or tubesheets.

x

Installed two-piece hammer-in plugs are difficult to remove.

10.1.3.2

Elastomer Plug

The elastomer plug type consists of a number of different plug designs and configurations. One design is shown in Figure 10-3.

10-5


Figure 10-3 Elastomer Plug (courtesy of Conco Systems, Inc.)

The plugs use an elastomer element or elements that are squeezed or expanded outward against the tube wall to form a seal. Most elastomer plug designs employ a mandrel to support one or more expandable elastomer seals. Tightening a nut or threaded member on the mandrel compresses the seal(s) along the mandrel. This causes the seal to expand radially outward into contact with the tube wall. Installation forces are established using either a prescribed number of turns or a prescribed torque value. A simpler push-pull elastomer-type plug design is also available. The push-pull plug is stretched during installation. This action causes the plug diameter to shrink and allows the plug to slip into the tube end. This plug type seals as the installation load is released and the plug relaxes/expands to its original size. Figure 10-4 shows an example of how one elastomer plug design works.

10-6


Figure 10-4 Elastomer Condenser Plug Diagram (courtesy of Torq N Seal™ )

Plugs with elastomer seals alone can provide working pressures to 500 psi (3.4 megapascals) and above. Plugs in this class are commercially available in a number of different elastomer compounds with mandrels and compression hardware available in materials ranging from 10-7


engineered plastics to metal alloys. Consideration should be given to operating temperatures and galvanic corrosion when selecting the tube plug materials. Other types of elastomer plug designs incorporate an integral set of expandable metallic gripping segments along with the elastomer seal(s). The grips allow higher operating pressures. Elastomer plugs seal over moderate tube end irregularities and can be used in coated tubes and tubesheets. Elastomer plugs rely on the friction created between their components and the tube wall to hold the plug in place. An example of this design is shown in Figures 10-5 and 10-6. These figures show an elastomer plug with an o-ring in the shelf and installed conditions. These plugs consist of a chloroprene expanding cylinder. An elastomer o-ring provides a positive seal. The plug is installed by tightening the bolt at the end to the specified torque. Various manufacturers specify the test pressure for their plug from 500 to 5000 psi (3.4 to 34.5 megapascal).

Figure 10-5 Mechanical Gripper-Type Plug, Shelf Condition (courtesy of Powerfect, NJ)

Figure 10-6 Mechanical Gripper-Type Plug, Installed (courtesy of Powerfect, NJ)

10-8


Limitations for elastomer plugs include the following: x

The elastomer materials are subject to compression set and age hardening in the hot, wet conditions found in the condenser.

x

Over time, the elastomer materials lose their compressibility and become susceptible to leakage, vibration, and plug loss.

x

Elastomer plugs are generally acknowledged to have a limited service life. A program of periodic inspection, tightening, and possibly plug replacement should be incorporated into the preventive maintenance program.

Elastomer plugs can be used as a temporary fix when leaks are detected during in-service testing. These plugs are then removed and replaced by a permanent plug during the next scheduled outage. 10.1.3.3

Mechanical Plug

Mechanical plugs are metal plugs that come in several styles. The breakaway plug uses a conical-shaped tapered pin that is drawn axially through an expandable metallic sealing ring. An example is shown in Figure 10-7.

Figure 10-7 Mechanical Breakaway Plug (courtesy of Expansion Seal Technologies)

As the ring expands, it contacts and is compressed against the tube wall forming a leak-tight seal. External ridges or serrations along the circumference of the sealing ring compensate for tube wall defects and tube roundness. The plug is installed using a compact hydraulic ram or manual plug installation tool. This plug type is initially smaller than the tube inside diameter and might be recessed into the tube end for installation. This style plug can also be used to plug a tubesheet hole. This style plug should not damage the tube or tubesheet coatings. Consideration should be given for proper plug material selection. These style plugs provide a high degree of seal integrity and are easily removable. Another type of mechanical plug is the thimble-style plug. This plug is a thin-walled, thimbleshaped metallic plug that is expanded into the tube or tubesheet hole. Mechanical roller expanders or hydraulic expansion methods are used for installation. Care should be exercised when installing this plug to not over-expand the plug. This can result in tube joint failure of 10-9


adjacent tubes. Generally, a fiber hammer-in taper plug is driven into the open end of the thimble after it has been expanded. This is to identify the tube that is plugged. Consideration should be given to ensure proper plug material selection. The installation method is time-consuming, requires a skilled installer, and is equipment intensive. Caution should be used when installing the hammer-in plug to prevent damage to adjacent tubes. When properly installed, this style plug provides a high degree of seal integrity and can be removed using conventional tube pulling techniques. An example of a thimble-style plug is shown in Figure 10-8.

Figure 10-8 Thimble-Style Plug (courtesy of Expansion Seal Technologies)

10.1.3.4

Welded Tube Plug

Welded hammer-in taper plugs consist of either a solid or thimble-shaped conical plug that is driven into the tube end or tubesheet hole. The plug is then seal-welded to the tube, tubesheet cladding, and/or tubesheet base material. Welded tube plugs must be compatible with the materials to which they are welded. Caution is needed when driving in the plug prior to welding to prevent cracking the tube and/or tubesheet. Adequate pre-heat and post-weld stress relieving procedures should be followed to prevent weld failure, warping of the tubesheet, and damage to adjacent tube joints. When properly installed, these plugs offer high working pressures and a high degree of seal integrity. Other considerations to include when evaluating this plugging method are: x

Welded tube plugs should not be used in coated tubes or tubesheets.

x

Qualifying the welding procedure and welders, and performing the actual welding process, are time-consuming tasks.

x

Welding difficulties include the skill required for welding the alloys, the cramped space, and the wet conditions in the waterbox.

x

Welded tube plugs are difficult to remove.

10-10


10.1.3.5

Tube Plugs Available

Table 10-1 lists some of the tube plugs on the market, their composition and characteristics. Corresponding tube plugging procedures for the plugs listed in Table 10-1 are listed in Appendix C. These procedures are the current ones given by the manufacturer and can change. It is a good idea to consult the most recent set of installation instructions from the vendor before installing the plug.

10-11

10-12

Conco Systems, Inc. www.concosystems.com

Manufacturer Atlantic Group www.atlanticgrp.com Bemark Associates, Inc. 1-302-234-7587

Table 10-1 Tube Plug Data

Maintenance Repairs [3]

Chloroprene and brass, bronze, stainless steel, or titanium



Chloroprene and vulcanized fiber and brass, bronze, stainless steel or titanium

Expanding tube plug EX-3

Expanding tube plug EX-4

Expanding tube plug EX-F

Brass, carbon steel, stainless steel, or titanium

K-Span Plug

High confidence tube plug

Composition Brass plug with a fiber jacket

Type of Plug Brass and fiber jacketed


Characteristics Water or steam application only, maximum temperature is 350 °F (177°C) Sizes for 5/8 in -1 1/4 in (14 - 32 mm) tube, expansive range is 0.040 in (1 mm), up to 800 psi (5.5 megapascal), up to 400°F (204°C), for tube or tubesheet plugging. Sizes for 3/4 in - 1 1/4 in. (19 - 32 mm) tube, seals up to 500 psi (3.4 megapascal). Can be used on coated tubesheets. Plug has machined serrated adjustable grippers. Sizes for 5/8 in - 1 1/4 in (14 - 32 mm) tube, large outside washer on one end allows plug to fit flush with tubesheet and not be pulled into tube by vacuum, tested to 375 psi (2.6 megapascal). Sizes for 5/8 in - 1 1/4 in (14 - 32 mm) tube. Equal-size washers allow plug to be positioned in tube beyond flush of tubesheet. Tested to 370 psi (2.5 megapascal). Sizes for 5/8 - 1 1/4 in (14 - 32 mm) tube. Chloroprene expands and seals when tightened. Vulcanized fiber expands when wet for gripping action.

Expansion Seal Technologies www.expansionseal.com

Manufacturer Conco Systems, Inc. (contd.) www.concosystems.com

Table 10-1 (cont.) Tube Plug Data

Brass and copper-nickel alloy plug materials available. Other alloys available on request.

Perma plug condenser plug/expandable metal plug

Expandable thimble plugs

Brass, bronze, stainless steel, or titanium

Pin and collar

Neoprene, silicone or Viton™ elastomer seals with brass, bronze, stainless steel, or titanium hardware and locknut. Other material combinations available on request. (Viton is a registered trademark of DuPont Dow Elastomers.) Brass, carbon steel, stainless steel, copper nickel, and titanium alloys standard. Other alloys available on request.

Brass, bronze, stainless steel, or titanium

Pin plug type 1

VibraProof condenser plug/expandable elastomer plug

Composition Vulcanized fiber

Type of Plug Pin plug


10-13

Plug sizes available to fit tube and tube hole IDs from 0.491 in to 1.336 in (12.5-33.9 mm). Installs in seconds. Helium leak-tight to 1 x 10-10 cc/sec. Conservatively rated in condenser service for operating pressures in excess of 300 psi (2 megapascal). Will not damage coated tubes and / or tubesheets. Precision-controlled installation load will not damage or distort tube or tube joints. Permanent plugs, yet easily removable. Plug sizes available to fit 5/8 in to 1 1/4 in (14-32 mm) tubes.

Characteristics Sizes for 5/8 - 1 1/4 in (14-32 mm) tube. Vulcanized fiber’s hydroscopic action expands when wet. Sizes for 5/8 - 1 1/4 in (14-32 mm) tube. One-piece plug for temporary or permanent tube plugging. Sizes for 5/8 - 1 1/4 in (14-32 mm) tube. Two-piece plug for temporary or permanent tube or tubesheet plugging. Plug sizes available to fit 3/8 in to 1 1/4 in (9.5-32 mm) tubes. Can be used in coated tubes and tubesheets. Large positioning washer resists vacuum. Operating pressures to 150 psi (1 megapascal).


10-14

Torq N' Seal JNT Technical Services, Inc. www.torq-n-seal.com www.tubeplug.com

Manufacturer Heat Exchanger Products, Inc. (HEPCO) www.hepcoplugs.com

Table 10-1 (cont.) Tube Plug Data


Type of Plug

Nylon plug body, silicone rubber seal, scotch brite scouring disc, stainless steel expansion screw and washer Molded rubber body

Silicone heat exchanger plug Push 'N Seal

Condenser plug

Carbon steel, brass, stainless steel, or cupra nickel Buna-N rubber

Composition Brass nut and bolt assembly, collar and washers made from a non-watersoluble, hard plastic called hytrel. Silicone parts are a vulcanized silicone rubber. 316 stainless steel nut and bolt assembly, collar and washers made from a non-water-soluble, hard plastic called hytrel. Silicone parts are a vulcanized silicone rubber. Titanium nut and bolt assembly, collar and washers made from a non-watersoluble, hard plastic called hytrel. Silicone parts are a vulcanized silicone rubber. Ultem nut and bolt assembly, collar and washers made from a non-watersoluble, hard plastic called hytrel. Silicone parts are a vulcanized silicone rubber.

High-pressure tube plug

Ultem

Titanium

Stainless steel

Brass


No metal parts on this plug, eliminating the concern of any galvanic action inside the tubes. Will not fracture/distort tube or tubesheet, easily installed/extracted, reusable, ideal for coated surfaces, noncorrosive. One-piece plug that will expand approximately 0.030 in. (762 µm) to seal. Economical, low-pressure plugs designed for temperatures up to 275 °F (135°C) and 150 psi (1 megapascal). Up to 250 °F (121°C) and 150 psi (1 megapascal).

Will not fracture/distort tube or tubesheet, easily installed/ extracted, reusable, ideal for coated surfaces, non-corrosive.

Will not fracture/distort tube or tubesheet, easily installed/ extracted, reusable, ideal for coated surfaces, non-corrosive.

Characteristics Will not fracture/distort tube or tubesheet, easily installed/extracted, reusable, ideal for coated surfaces, non-corrosive.


10.1.4 Tube Plug Removal It is necessary to remove a tube plug that is leaking. Also, prior to any tubesheet repairs or condenser retubing, the tube plugs must be removed. The following is a discussion of tube removal techniques for the different types of tube plugs. 10.1.4.1

Hammer-In Taper Plugs

When the large end of the taper pin projects out of the tube end, the following techniques should be used: 1. Drive a 12 point socket into the exposed end of the plug. Install a socket wrench or breaker bar and turn to twist the plug from the tube end. 2. Using a hammer and cold chisel, strike the exposed end of the tapered pin from the opposing sides parallel to the plane of the tubesheet. This might loosen the plug for removal. 3. Use a conventional pipe wrench to grasp the exposed end of the pin. Rotate the wrench to twist and loosen the plug. 4. Use a center punch to mark the exposed end of the plug. Drill and tap the plug to allow attachment of a slide hammer, tube spear or plug removal tool. The slide hammer/tube puller is operated until the plug is pulled from the tube end. A typical plug removal tool is a combination slide hammer and tube spear. An example of a tube-pulling tool is shown in Figure 10-9.

Figure 10-9 Plug Removal Tool (courtesy of Expansion Seal Technologies)

In situations where the plug is flush with or recessed within the tube end, the following techniques should be considered.

10-15


x

Mark the exposed end of the plug with a center punch. Drill and tap the plug to allow attachment of a slide hammer, tube puller, or plug removal tool. Operate the slide hammer or tube puller until the plug is pulled from the tube end.

x

It might be possible to remove a stuck plug by striking it from the opposite end of the tube. Using a rod that is longer than the tube, insert the rod into the tube and drive it against the plug.

For the two-piece hammer-in plugs, the tapered pin or entire plug assembly can be removed using any of the techniques outlined above. If the pin is removed, leaving the ring within the tube end, the ring can be removed using any of the following techniques: x

Thread a tapered tube pulling spear or plug removal tool into the bore of the ring. Attach a slide hammer or tube puller to the spear. Operate the puller or slide hammer to withdraw the ring from the tube end.

x

Using the bore of the ring as a drill guide, drill through the ring with successively larger drill bits until the ring can be withdrawn from the tube end. Exercise caution during drilling to prevent the drill from moving off center or drilling at an angle. Damage to the tube or tubesheet could occur that will make re-plugging difficult.

x

Use successively larger, stiff bristle, metal brushes to wear away the ring material from the inside diameter. Exercise caution to prevent the brushes from damaging the tube bore.

10.1.4.2

Elastomer Plugs

For the elastomer plugs, the plugs are loosened by unscrewing. Once loosened, the plug might slide out of the tube end. If the plug is stuck within the tube, pry the plug loose using a claw hammer or tube pulling device. Exercise caution to prevent damage to adjacent tube ends during the removal process. 10.1.4.3

Mechanical Plugs

For the mechanical plugs, remove any remaining portion of the plug from the exposed end of the pin. Thread a plug removal tool into the tapered pin. Use the slide hammer to drive the conical pin back through the ring into the tube. Thread the tapered spear into the ring and operate the slide hammer to pull the ring and pin from the tube end. For the thimble style plugs, thread a conventional tube spear or plug removal tool into the plug body. Attach a slide hammer or hydraulic tube puller and operate the tool until the plug is pulled from the tube end. 10.1.4.4

Welded Plugs

For tube plugs that are seal welded, the weld material should be removed using a grinder. The exposed end of the plug should be marked with a center punch, drilled, and tapped to allow attachment of a slide hammer, tube puller, or plug removal tool. Operate the tool until the plug is pulled from the tube end. 10-16


10.2 Tube Inserts [3] Using tube inserts to solve the problem of leaking tubes requires advance planning for ordering and installing the insert. A common practice is to use flared or flanged plastic inserts or tube protectors designed to alleviate the inlet end erosion. Polymeric inserts are designed to fit snugly when installed in the affected tubes. The insert tube interference fit becomes more pronounced after a period of time because the polymers used are designed to swell by water absorption upon exposure. Non-water-absorptive polymeric inserts (such as nylon) are typically secured in position with adhesive sealants. Non-metallic inserts do not cause galvanic corrosion of tubes or tubesheets. Other disadvantages of polymeric inserts are: x

Inserts backing out of tubes

x

Insert flare breaks

x

With a reduced tube inlet diameter, tube cleaning in general is more difficult, including the sponge ball cleaning system.

x

Eddy current testing of the tubes is more problematic because of the narrowing of the tube inside diameter for the length of the insert and at the step from the insert to the original tube diameter.

x

Erosion of tubes at the insert-to-tube interface when the insert is not properly feathered. While the inserts can eliminate the original inlet end erosion, they can also cause end-step erosion further along the tube and thus introduce a different kind of problem. See Figure 10-10 for a tube insert.

Figure 10-10 Tube Insert [24]

As an alternative, the use of metallic, thin-walled inserts or shields, provides a more durable solution. Metal alloy inserts are six- to eight-inch (15 to 20 cm) long thin wall tubes that have an outside diameter slightly less than the inside diameter of the tubes to be restored. First introduced in 1976, these shields are made with a chamfered outlet end. This greatly reduces the chance of 10-17


end-step erosion. They are also hydraulically expanded into the host tube. This structurally reinforces the tube. The shields are then flared so that they conform to the tubesheet profile. There must be a careful selection of the insert material based on the tube material. A different insert material can sometimes be selected in order to combat a specific failure mechanism. Key Technical Point Metallic shields restore tube-to-tubesheet joint strength, extend bundle life, have no negative effect on heat transfer, and reduce the tube opening by a fraction of that associated with plastic tube inserts. An improved insert is shown in Figure 10-11.

Figure 10-11 Improved Tube Insert [24]

The long-term corrosion and erosion-corrosion resistance of the insert materials depends on: x

The galvanic compatibility of the insert, tube, and tubesheet materials

x

The circumferential and linear adhesion of the barrier material to the tube

x

The barrier’s wall thickness, downstream taper, and surface smoothness

x

The effectiveness of tube cleaning practices, particularly at the downstream interface between the tube and tube insert where sludge tends to accumulate Key Technical Point Corrosion-resistant insert materials typically specified are: AL-6X, AL6XN, 70-30, 85-15 or 90-10 Cu-Ni and 304 or 316 Stainless Steel. AL-6X is the most widely used insert material.

10-18


While appropriately specified and installed inserts eliminate condenser tube inlet end erosioncorrosion, highly corrosion-resistant inserts can create new corrosion problems, often as serious or more serious than the original event causing the need for the use of the inserts. The major insert-induced problems encountered are: x

Galvanic attack of inlet tubesheet ligaments

x

Galvanic attack of the condenser tubes at the interface between the downstream end of the insert and the tube

x

Under-deposit attack of condenser tubes at the downstream tube-to-tube insert interface

x

Erosion of the condenser tube at the downstream interface of insert and tube

x

Reduction in the accuracy of ET results of tube wall thickness at the tube-to-tube insert interface

x

Reduced effectiveness of sponge ball cleaning because of reduced tube inlet inside diameter

10.3 Tube Sleeves For cases where tube damage is localized to a specific region of the tube, a structural sleeve can be installed to bridge across the degraded area. The length of the sleeve is limited to the working space inside the waterbox, assuming the waterbox cover is not removed. Either roller expansion or hydraulic expansion can be used to create the sealing joint between the sleeve and the original tube. The material used for sleeving is metallic and compatible to the tube being repaired. A typical sleeve installation configuration is shown in Figure 10-12.

10-19


Figure 10-12 Sleeve Repair (courtesy of Framatome Technology)

10.4 Tube End Coatings [3] Key Technical Point An alternative approach to tube inserts for tube end erosion/corrosion problems is to apply a tube end epoxy coating that can halt the erosion process. The coatings are applied in multiple coats for a total coating thickness of 9 to 10 mils (229 to 254 µm). The coatings are applied into the tube end to the required depth, usually between 2 and 30 inches (5 and 76 cm), depending on the width of the waterbox. The metallurgy of the tube to be coated is not significant because the coating is compatible with all tube materials. Such coatings have been used in service and cooling water system applications for over 15 years and have also been successfully used with both freshwater and seawater environments. Each coat in the tube conforms to the tube wall and extends beyond the previous coat, so that a feathered 10-20


termination surface is achieved. This eliminates the possibility of step erosion occurring in the area where the coating terminates. The work is usually performed during an outage and the application of the coating is completed with the waterbox in place. It is highly recommended that throughout the application process, all environmental control equipment, such as dehumidification and dust collection systems, be placed in full operation. The tube end coating does not significantly reduce the internal diameter of the tube. Therefore, NDE procedures are not impaired. The tube end coating is also compatible with all on-line and most off-line tube cleaning methods. With metal scrapers, plastic nozzles must be used on the cleaning guns. Another off-line tube cleaning method involves the use of high-pressure water. Using water at a high pressure is, however, the preferred method for removing existing coatings. Great care must be taken when using high-pressure water to clean tubes, not to accidentally remove the coatings. When tube end coatings are selected as the method for repairing tubes, such coatings are usually applied in conjunction with the installation of a tubesheet coating/cladding system. If there are through-wall penetrations and/or plugged tubes, then tube coatings might not be the best solution. Because the tubesheet coating is 9 to 10 mils (229 to 254µm) in thickness, it is difficult to bridge over through-wall penetrations. Surface preparation and quality control of the anchor pattern along the tube length are key factors in the success of the application. The difficulties are greater with longer tube lengths. Tube end coatings are most beneficial for erosion/corrosion and pitted tube ends that are in service. If a tube has been identified as having a through-wall penetration, an insert has a better chance of restoring the tube end.

10.5 Full-Length Tube Liners [3] Using techniques similar to those developed with thin-walled metallic inserts, tube liners can also be inserted to cover the whole tube length. After cleaning the insides of the original tubes, the liner is installed. A bleed chuck is placed on one end and a pumping chuck on the other to seal the tube. The liner is then filled with water, the air is bled out, and a hydro-expansion pump is used to expand the liner to achieve an almost completely metal-to-metal fit. After remaining pressurized for a short time, the pressure is released and the water is drained out. Then the ends of the expanded liner are cut off and milled flush to the tubesheet. The tube ends are then rollerexpanded into the tubesheet to a predetermined wall-reduction specification. In this way, previously plugged tubes can be restored to active duty. While the tube end inserts have no adverse effect on heat transfer, it should be noted that fulllength liners do have a greater impact. Because the thickness of the liner is small, any degradation in the overall heat transfer coefficient is due to the metal-to-metal contact achieved between the liner and the tube during the expansion process.

10-21


Key Human Performance Point Tubes in service have defects. These defects or indentations can result from installation or in-service conditions. The liner might not be able to overcome all tube inside diameter defects and, thus, will not be expanded to meet the tube inside diameter by hydro-expansion. The defects create air pockets that can significantly retard heat transfer. Because of the uncertainty of the application results, it is recommended that heat transfer studies be conducted on several samples of the tubes to be lined. In this way, the effect on heat transfer can be established prior to the relining process being implemented in the field.

10.6 Full-Length Tube Coatings [3] The advent of full-length tube coating occurred in both Europe and Japan in the mid-1980s. It was introduced to protect tubing material from inside diameter pitting, from full-length tube wall thinning, and/or to prevent copper ions from being leached from condenser tubing directly into the circulating water. Key Human Performance Point The full-length tube coating material is applied with an average thickness of 2–4 mils (51–102 µm). However, the actual coating thickness selected has to be balanced between solving a particular problem and retaining sufficient tube heat transfer capability. Proper tube surface preparation can include washing with high-pressure water, mechanical cleaning, and abrasive blasting. The coating material is then applied using automated spraying equipment. Again, it is highly recommended that throughout the application process, all environmental control equipment, such as dehumidification and dust collection systems, be placed in full operation. In the early 1990s, a U.S. utility decided to coat tubes to prevent copper ion release from condenser tubes and the subsequent discharge of the ions with the circulating water into a coastal saltwater inlet. The concern was a violation of an EPA upper limit on allowable copper concentration in discharges into pristine water. This problem was solved successfully by applying a full-length tube coating but a small reduction in the tube heat transfer coefficient resulted. If the epoxy coating of the tube inner surfaces is to be the means for eliminating through-wall penetrations, other considerations must be reviewed. Because gravity causes the coating to be thicker toward the bottom of the tube, tube penetrations located toward the top of the tube circumference might not be sealed adequately. Surface preparation and quality assurance along the whole length of the tube is a key factor in the success of the application. The difficulties are greater with the longer lengths of tubes. Consequently, the epoxy coating of the internal surfaces of tubes should be approached with caution if the purpose is to eliminate leaks through tube wall penetrations. Also, impressed current cathodic protection systems can cause damage to the fulllength coatings.

10-22


In the evaluation of full-length tube coatings, the issue of cathodic protection on the tubesheet should be thoroughly investigated. Several tube coatings were tried at Florida Power Corporation [32] with some good results. Coatings can be successfully applied to condenser tubes to: x

Extend tube life and increase availability of condenser units by shortening the downtime experienced during retubing

x

Extend the life of condensers on older units whose remaining life is less than the life of a retubed condenser and at a lower cost

x

Limit copper levels discharged from tubes in routine operation to those allowed under new EPA or regulatory agency limits

x

Extend the life of tubes in one waterbox to correspond with the remainder of the unit’s waterbox tubes end-of-life or to meet budget and /or outage restraints

The first generation of coatings included the Metal Modified Siloxirane by Corrodex, the Modified Epoxy 600 EP by Plastocor, the Polyamine Epoxy by Keeler and Long and the Teflon Modified Epoxy Phenol by Corrodex. The second generation of coatings included an epoxy phenolic by Corrodex, the modified Siloxirane by Corrodex, a German epoxy, a urethane epoxy from Europe, and a modified epoxy from the United States. Additional coatings tested include reformulated Keeler and Long’s Polyamine epoxy No. 3250 V and Plasite 7156. In the testing done at Florida Power Corporation, dry sandblasting techniques successfully prepared tubes for coating. A cleaning lance, made of steel pipe fitted with a tungsten carbide cone-shaped spray nozzle, blasted clean 1,280 tubes per day using black beauty grits. A newly developed coating application system consisted of a diaphragm pump, fluid pressure regulator, patented spray nozzle and hoses, and an automated feeding and retrieving device. This system proved capable of coating three tubes simultaneously at a rate of 3,000 tubes per 8-hour shift. A complete condenser tube bundle of 5,700 tubes was coated. The side-by-side evaluation of the Florida Power Corporation’s Bartow #2 condenser showed that coated tubes remained cleaner for longer periods of time than uncoated tubes. Subsequent reductions in the frequency of tube cleanings resulted in labor savings. Tested after more than three years in service, the Bartow #2 coated condenser tubes offered more efficient heat transfer performance than uncoated tubes in the unit. Furthermore, the coated tubes showed no sign of deterioration after four years of service. Tests conducted on the Bartow #2 condenser tubes clearly indicate that properly prepared and coated tubes can perform with no negative effect on unit heat rate. However, if an improper coating is selected or a coating is applied too thickly, heat rate penalties will likely be incurred.

10-23


10.7 Re-Expanding the Tube-to-Tubesheet Joint [3] Sometimes the joint between the tube and the tubesheet leaks. When this occurs, one remedy is to mechanically expand the tube again, using a specially designed mandrel driven by an electric motor. These mandrels are provided with between three and five rollers. The thickness of the tube to be expanded determines which mandrel is selected. Care must be taken to ensure that the allowable wall reduction is not exceeded. Re-expanding can solve the joint leak problem, however, if the leak was caused by galvanic corrosion between the tube and tubesheet, the problem might return. This is because of the continuing degradation of the tubesheet from galvanic action. Also the re-expanding of tubes might place stresses on adjacent tubes and result in their experiencing tube-to-tubesheet joint leaks. Further, when re-expanding tubes into the tubesheet that is made from a copper-bearing alloy, such as Muntz metal, naval brass, silicon bronze, etc., great care should be taken to avoid damaging the boreholes in the tubesheet.

10.8 Coating of Tubesheets [3] Tubesheet coating has been used by the power industry for the past 30 years. The coatings started as thin-film systems (< 30 mils or 762 µm) and evolved into tubesheet cladding systems. Some of the reported results include: x

Restoration of the tube-to-tubesheet joint strength, making them leakfree

x

Halting of the corrosion process

x

Resistance to erosion/corrosion at the tubesheet surface

x

Inertness to chemical cleaning and water treatment programs

A cladding system consists of a thickness of 200 mils (5.08 mm) or more of an epoxy coating. This is applied to a tubesheet in multiple coats by a specialty contractor. Abrasive blasting of the tubesheet is required and the tubes must be protected from the blast by the insertion of blast plugs. Similarly, when subsequently applying the coating to tubesheets, plugs need to be inserted into the tubes to protect them. Otherwise, NDE procedures and tube cleaning can be hampered by material mistakenly left in the tubes. Tubesheet cladding projects have been completed with the unit on-line. Waterbox isolation is required for this to occur. It is highly recommended that throughout the cladding process, all environmental control equipment, such as dehumidification and dust collection systems, be placed in full operation. A picture of a tubesheet with an epoxy cladding is shown in Figure 10-13.

10-24


Figure 10-13 Epoxy Tubesheet Cladding (courtesy of Plastocor)

Key Technical Point Manufacturers recommend that epoxy coatings not be subjected to high temperatures (> 170°F (76.6°C)) or allowed to freeze. If tubes, mounted in tubesheets that have had the cladding applied subsequently, leak, they should not be plugged with tapered brass or fiber plugs. Expandable plugs are preferred because they do not put pressure on the coating. Plugs should never be hammered into tubes in tubesheets after they have been coated. When cleaning the surface of the tubesheet with high-pressure water, pressures of more than 3,000 psi (20.7 megapascals) should never be used. Also high-pressure water should not be used to clean tubes that have been coated internally. Finally, tube-cleaning nozzles should never be made from brass or other metals. The nozzles should be made from a soft plastic material to prevent physical damage to the epoxy coating.

10.9 Tube Staking for Vibration [24] Anti-vibration staking can be performed when tube vibration is a problem. Staking is the insertion of a rod between the tube rows locking the tubes in place. The rod prevents tube oscillation and subsequent mechanical damage. The condenser tube stakes are generally fabricated from stainless steel (Figure 10-14). Micarta, which is a much lighter material that cannot be bent, is also used. A gap of 3/4 inch (19 mm) between tube rows is needed for the insertion of a micarta stake (Figure 10-15).

10-25


Figure 10-14 U Stainless Steel Tube Stake [33]

Figure 10-15 Micarta Condenser Tube Stake [33]

Another type of tube stake is the Cradle-Lock® shown in Figure 10-16. The stake is stamped from stainless steel and is in a V shape with indentions at the tube locations. When installed, the spring action of the V-shaped stake with the indentions locks the stakes and tubes into a single, vibration-free unit. These stakes do not shift over long periods of operation as other design stakes can do.

10-26


Figure 10-16 Cradle-Lock® Tube Stake (courtesy of the Atlantic Group)

A non-metallic, polymer stake known as a Lath® has been used in condensers where the steam temperature does not exceed 300ºF (149ºC). The stake is an extruded polymer tube that has the air evacuated, is flattened in ribbon form, and sealed at the end. It is installed by threading the Lath into the tube bundle and the end is cut to allow the air to re-enter. The polymer tube tries to retake its tubular form, thus cradling the condenser tubes. The pattern of staking will vary with the condenser manufacturer’s tube bundle design. The staking pattern for a typical design is shown in Figure 10-17.

10-27


Figure 10-17 Typical Condenser Tube Staking Pattern [33]

Staking should be provided all the way around the top of the tube bundle and approximately 80 percent of the way down the side of the tube bundle. These areas see the impingement of wet steam causing destructive tube vibration. Additional staking might be required at high-energy dumps below these levels. If this involves staking the bottom and lower 20 percent of the bundles, specially designed clamping devices might be required. Staking is generally the least 10-28


desirable method of minimizing vibration because periodic inspection of the stakes is required. In some cases, there might not be a practical alternative. In condensers that have been retubed with titanium, the wall thickness of the titanium tubes is smaller than the original material tubes. This can create vibration problems when using the same tubesheet support spacing. The addition of tube stakes is needed to prevent any damage from vibration.

10.10 Waterbox Repairs [12] Waterbox restoration can include coating the entire waterbox, the most corroded section of the waterbox, or patch repair of through-wall penetrations. Key Technical Point The material selection for coating waterboxes depends on whether the waterboxes are new or have been in-service, coated in a manufacturer’s shop, or coated inside the plant. When coating new waterboxes, epoxies, rubber lining, or solvent-filled epoxies (coal tars) are used. Waterboxes coated inside the plant use epoxy coatings for performance, longevity, and personnel safety considerations. Waterbox coatings are often used with cathodic protection systems. A coating greatly reduces the anodic area to be protected by the cathodic protection system. Generally, the most affected area in the waterboxes from galvanic interaction is the perimeter adjacent to the face of the tubesheet. This area can be coated but the problem might be translated to another area of the waterbox. Coatings or linings protect the condenser components from various corrosion and erosion mechanisms. They act as a barrier between the corrodable metals and the circulating water and rehabilitate degraded metal surfaces by filling pits and depressions. This results in the restoration of a corroded surface to a smooth surface and helps to control biofouling. Leak repairs require some waterbox drying and localized sandblasting or chiseling. Carbon steel patchplates sized to cover through-wall holes are then used with elastomeric coating materials suitable for circulating water exposure. The patchplates in the elastomer coating promote leak tightness while providing renewed structural integrity. This, however, is a temporary repair. It might be necessary to replace the waterbox. This decision is based on the condition of the waterbox and the cost to perform repairs. While cast-iron was used as a waterbox material in the past, the newer waterbox materials include carbon steel, carbon steel clad with 316 or 317 stainless steel, 316 or 317 stainless steel, aluminum bronze, and titanium. The tasks associated with the waterbox repair and replacement options are summarized in Table 10-2.

10-29

EPRI Licensed Material Maintenance Repairs [3] Table 10-2 Waterbox Tasks for Repair and Replacement [12] Task

Waterbox Patch

Waterbox Coating

Waterbox Replacement

Interference Removal

NO

NO

YES

Waterbox Removal

NO

NO

YES

Surface Preparation

YES

YES

NO

Waterbox Coating

YES

YES

NO

Waterbox Installation

NO

NO

YES

Interference Reinstallation

NO

NO

YES

Cathodic Protection System

YES

YES

YES

10.10.1

Waterbox Coating Techniques [25]

As with all coating projects, surface preparation, choice of abrasive, source of compressed air, dehumidification (in-line heaters), dust collectors, etc., need to be considered. The coating of the waterbox includes several techniques for a successful application: x

Surface Preparation and Lining - Heavy deposits of sludge or grease should be removed by scraping or dry wiping before general solvent cleaning and abrasive blasting. Solvent wiping such deposits first has proven unacceptable because this process tends to smear the contamination. Compressed air for blasting operations should be free of all trace amounts of oil and water. When blast cleaning on or adjacent to stainless steel surfaces, the abrasive should contain not more than a trace contaminant of iron. Do not use steel shot or black beauty. These tend to become embedded in the surface and can produce film flaws. Before coating, damage to the internal surfaces should be repaired and all residue of blast abrasive removed from the surface to be coated. The final step of the cleaning operation should be vacuum cleaning. Blowing down with air is not an acceptable method of removing dust.

x

Coating Material - Coating material should arrive in the original, unbroken containers. The container labels should be clear and intact. The date of manufacture or the expiration date should be marked on the label. Coating materials should be less than 6 months old when applied. Manufacturer’s instructions should be followed if a shorter shelf life is specified. If the coating material is found to be skimmed over to the extent that removing it would affect the solids content, the material should not be used. Mixed materials should be strained before use.

10-30


x

Coating Application - The coatings should be applied in accordance with industry standards and the applicable instructions of the coating manufacturer. The following considerations should be detailed in the coating procedures: –

Material storage

–

Surface preparation (finishing details, degreasing methods, type of blasting equipment, and abrasive)

–

Ambient conditions (method and frequency of monitoring)

–

Compressed air (quality, method, and frequency of monitoring)

–

Material mixing (ratio of components, equipment used, induction period, and so on)

–

Application equipment (spray unit type, tip, hoses, and so on)

–

Material potlife (as a function of temperature)

–

Re-coat window (limits, parameters affecting)

–

Ventilation (required capacity of equipment used to maintain environment with required limits during application)

–

Force curing (available system capacity, heating cycle)

–

Film repairs (means of restoring lining at areas outside thickness limits, holidays and damaged spots, differentiate between nominal and major repairs)

Runs and sags should either be brushed out while the material remains wet or removed by sanding and touched up. Adequate traps and separators should be provided to remove oil and condensate from the compressed air supply. Solvent left in spray equipment to prevent overnight hardening or for cleaning and flushing should be removed before performing subsequent coating work. All welds, corners, edges, and rims should be brush-coated prior to general spray applications of the first coat. The coating should be worked vigorously into crevices; the material should be thinned as required to facilitate brushing. The environment in the coating area should be controlled to ensure that the minimum temperature is not less than 60qF (15.5qC) and that the surface to be lined is at least 5 degrees warmer than the dew point. The lining material manufacturer’s recommendations should be observed with regard to minimum and maximum drying times between coats. The ambient temperature in the coating area will be a function of the drying time. Ample ventilation air should be provided to permit total removal of solvents and to maintain an atmosphere well below the explosive limit. The coating should be free of visible fish-eyes, craters, and bubbles as well as overspray lamination to the extent that no visible imperfections remain. 10-31


A forced cure and a high-voltage, high-frequency film continuity test are the final steps in completing a coating system. To improve the probability of a successful final test, it is suggested that a low-voltage (wet sponge type) holiday detector test be performed and imperfections repaired prior to the forced cure. It should be noted that high-voltage spark testing cannot be performed on tubesheet cladding systems in the areas of the tube field. Direct-fired oil heaters should never be used for curing. The coating operation should not start until after the waterboxes are bolted in position and the final leak test is completed. 10.10.2

Waterbox Flange Seams [25]

It is important to seal the interface between the tubesheet and the waterbox in order to eliminate corrosion beneath the tubesheet-to-waterbox gasket surface. This can result in condenser water and/or air in-leakage along the corrosion path and through the bolt holes. The sealing of this interface has been performed successfully over the years by coating the interior surface of the tubesheet and waterbox flange joint. The coating materials developed for this purpose have been designed to withstand the potential for differential movement between the tubesheet and waterbox. As with all applications of epoxy material, proper surface preparation and the use of environmental controls are recommended in order to achieve successful long-term results.

10.11 Tubesheet Repairs [12] The decision to perform tubesheet repairs or to install new tubesheets depends on the problems with the tubesheet. If the tubesheet face is deteriorated and the thickness has been reduced, then a coating repair will not restore the structural integrity of the tubesheet. If the tubesheet has erosion of the tubehole surfaces with excessive leakage of cooling water to the condensate then coatings might be a viable option. The decision to coat tubesheets must include an assessment of tube conditions. When replacing the tubesheet, the tubes must be cut inside the tubesheet face for removal. This necessitates that new tubes be installed. It is possible to coat the existing tubesheets using the existing tubes if the tubes are in good condition. Other considerations associated with tubesheet repairs are surface preparation and waterbox coating. Prior to the coating application, the existing tubesheet surfaces must be refinished to an acceptable profile and cleanliness. This is usually accomplished by grit blasting. Also, if the tubesheets have been previously coated, then the old coating must be removed. Depending on the tube material, coating of the tubesheets can result in the waterbox material becoming sacrificial to the tube material. The coating of the waterbox surfaces might be required if the tubesheets are coated.

10-32


Table 10-3 shows the tasks associated with tubesheet repairs and replacement. Table 10-3 Tubesheet Tasks for Repair and Replacement [12] Tasks

Tubesheet Repairs

Tubesheet Replacement

Interference Removal

NO

YES

Waterbox Removal

NO

YES

Surface Preparation

YES

NO

Tubesheet Coating

YES

YES

Waterbox Coating

YES

NO

Tubesheet/Tube Removal

NO

YES

Tubesheet/Tube Installation

NO

YES

Waterbox Installation

NO

YES

Interference Reinstallation

NO

YES

10.12 Tube Pulling [25] It might be necessary to remove one or more tubes from the condenser because of damage or for destructive metallurgical analysis. After the unit is shut down, the condenser has cooled and the waterbox doors are opened, the process of removing a tube can begin. If a tube plug or tube insert is present, these must be removed first. The tube can then be cut free from the tubesheet on the end opposite the removal direction with an internal tube cutter. The tube should be cut a minimum of 1/2 in (1.3 cm) behind the steam side face of the tubesheet. The tube-to-tubesheet joint is broken using a hydraulic tube extraction device. The device is operated by inserting the head into the tube and actuating it. This causes the draw bar to exert a radial force and engage the teeth with the tube. As the device retracts, it pulls the tube out approximately 4 in. (10 cm) from the tubesheet. This breaks the tubesheet joint. The tube can then be extracted through the openings in the waterbox. It is then necessary to plug both ends of the tubesheet. Plugging the tubesheet end of the pulled tube hole is an important operation. If a plug from the tubesheet becomes dislodged, the consequences of such a large leak can cause a forced outage. Use of a tube plug and tube plugging method with a high degree of seal integrity is recommended.

10.13 Miscellaneous Repairs [3] Experience has shown that water in-leakage can be caused by leaking piping that runs through the condenser and/or waterbox. One example is drain piping from a low-pressure turbine bearing that runs vertically below the bearing through the waterbox. Leaks from such sources are hard to locate because they are hidden from view and the leak rates are very small. It is important to review plant drawings to identify all sources of potential leaks.

10-33


11 REMAINING LIFE, MATERIALS, AND CONSTRUCTABILITY [3,12]

Condenser tube leaks are the major source of water in-leakage and a cause for reduced unit generating capability. The Operating Plant Experience Code data (Section 8.1.5) from April 1998 to June 2000 lists 44 outage events because of tube leaks. Tube plugging is the preferred method for eliminating tube leaks, up to the point at which the percentage of tubes plugged has significantly impaired heat transfer capacity. Condenser design is such that there is typically excess surface area available in the form of extra tubes to allow as many as 10% of the tubes to be plugged without reducing the effective heat transfer capacity of the unit [12]. This reduction in heat transfer capacity can occur at any time when more than 10% of the tubes are plugged. At this point, further tube plugging reduces condenser performance and the capability of the unit for full power production. Utilities typically then consider retubing the condenser to restore performance and extend the operating life expectancy of the unit. Experience with new materials, new tools, and new techniques has significantly reduced water in-leakage problems due to tube leaks and has improved condenser reliability. This has allowed state of the art condenser retubing methods to advance appreciably over the past 10 to 15 years. In addition to the standard, one-for-one, tube replacement technique, modular tube bundle replacements have been very successful using shop-fabricated modules. Consequently, units considering condenser retubing are not faced with only one option, that is, to replace the existing tubes with new tubes of the same material and construction. In most cases, condensers operating with the original materials have experienced performance problems. The majority of problems include water chemistry (both cooling water and condensate), tube fouling, and tube wall thinning issues. The design of the tube bundle replacements should take this experience into account. Because condenser retubing represents a major capital investment, economic factors weigh heavily in the decision-making. Key Technical Point The current industry experience has been to replace copper-bearing alloys with high alloy, pit-resistant steels and titanium. These materials are significantly lighter in weight and higher in yield strength, but they have lower thermal conductivities than the copper-bearing alloys. Use of these newer materials can significantly affect the performance characteristics of the condenser. Typically, thinner-walled tubes of the same outside diameter are selected from these alloys in order to reduce the tube wall thermal resistance and compensate for the loss in thermal conductivity. This tradeoff results in a larger tube side flow area but lower flow velocity. The lower flow velocity increases the fouling potential for the condenser tubes and might require the 11-1

EPRI Licensed Material Remaining Life, Materials, and Constructability [3,12]

addition of an on-line tube cleaning system. The lighter weights of the tube bundles also result in a change in the condenser support loads and might increase the condenser hold-down requirements. Key Technical Point Another consequence of retubing with one of the newer materials is the likely need for additional tube support plates or tube staking to reduce the tendency of the tubes to vibrate. More information on tube staking can be found in Section 10.9. There is the potential for brittle fracture of these high strength materials. The high yield strength of these materials makes it more difficult to seal the tube-to-tubesheet joints if the original copper-bearing alloy tubesheets are used. The galvanic compatibility of the new tubes with the tubesheet has to be considered. This might result in the need to clad or coat the tubesheet and/or provide a cathodic protection system. Condenser retubing is a very complex issue involving many parameters. A comprehensive engineering and economic evaluation should be performed to arrive at the best retubing option for a given unit and site location. Most of the concerns that should be considered in a comprehensive retubing evaluation are listed randomly as follows: x

Cooling water chemistry

x

Cooling water flow capacity

x

Seasonal temperature variation

x

Unit type (PWR, BWR, fossil)

x

Seasonal unit performance with old versus new tubes

x

Unit load and capacity factors

x

Condenser design configuration (series/parallel zones)

x

Tubesheet evaluation

x

Condenser uplift evaluation

x

Current performance issues (vibration damage, air leakage, backpressure limits)

x

Condenser condition (tubesheets, support plates, waterboxes)

x

Utility’s condenser experience (tube plugging, cleaning)

x

Utility’s condenser preferences (materials, maintenance techniques)

x

Economic parameters (discount rate, labor rates, replacement power rate)

x

Material availability

x

Outage window

x

Staging and warehouse space

x

Pull space

11-2


x

Load paths

x

Rigging and handling equipment

x

Complete versus partial/staged retubing

x

Modular versus tube-for-tube technique

x

Desired life of new tubes

x

Availability of on-line tube cleaning system

x

Ability to isolate waterboxes for on-line maintenance

x

Radioactive contamination level

x

Disposal options for old material

11.1 Remaining Life Assessment [12] Determining the remaining life of condenser components consists of the following assessments: x

Operation and Maintenance Records – Appropriate tube plugging and other maintenance records reveal present and past problems within the condenser. This includes the rate at which the conditions might be changing. In addition to providing location and date of plugging, possible reasons for failure should be recorded.

x

Historical Data – Industry data defining expected component life could provide a basis for more extensive condition analysis.

x

Non-Destructive Examination (NDE) – The use of NDE testing can provide valuable information on the remaining life of condenser components. Testing techniques include: Visual Inspection (VI), Dye Penetrant Testing (PT), Magnetic Particle Testing (MT), Eddy Current Testing (ET), and Ultrasonic Testing (UT). Additional information on NDE testing can be found in Section 9.4 and on NDE testing techniques in Section 11.1.1.

x

Destructive Examination – Destructive examination of selected tube samples by metallography, micrometer measurements, etc. should be performed to verify NDE results and to confirm specific failure mechanisms. It is very difficult to predict remaining life without the benefit of destructive examination results.

11.1.1 NDE Testing Techniques Used to Assess Remaining Life NDE testing techniques can provide a valuable assessment of condenser component remaining life. For example: x

Visual Inspection can be performed on waterboxes, tubesheets, tube ends, condenser shell, structural components, support plates, peripheral tubes, internal baffles, spargers and hotwell. Examples of VI findings might include: –

The location of failed tubes within a tube bundle. This often identifies the probable cause of failure. Tube failures primarily occurring in the periphery suggest outside diameter impingement or water level problems. Problems with brass tubes in and 11-3


around the air-removal zone suggest condensate grooving. High failure rates in low portions of the bundle suggest siltation problems. –

Substantial differences in the amount of corrosion occurring between the upper and lower half of a tube. This evidence suggests possible siltation, lay-up problems, water level problems, and so on.

x

Dye penetrant testing can be used to verify the crack indications if visual inspection indicates cracks.

x

Magnetic particle testing is used to detect cracks in spargers, and penetration and baffle welds.

x

Eddy current testing is used to examine the condition of the installed tubes. An internal probe is used for the specific tube bore size. The probe contains an alternating current (AC) coil. When the coil is energized, an electrical eddy current field is established around the tube. Wall thinning, cracks, pits, and other defects interrupt this field causing a measurable impedance change in the coil. Indication of condenser tube defects are shown on a visual screen and recorded. The nature and magnitude of all defects are determined by comparison of signals obtained from the tube tested with signals obtained from a reference standard tube. Test results can be evaluated as they are obtained during testing.

x

For ultrasonic testing, the high-frequency sound waves are induced in the subject material and the reflections of the sound waves caused by defects in the material are measured electronically. The sound is generated by a probe containing a piezoelectric disc that converts electrical current into mechanical vibrations. The results are recorded and compared to calibration standards.

11.1.2 Remaining Life Formula [34] To predict the operating remaining life of a condenser, the following formula can be used: RL = (PL-PT)/GR

(eq. 11-1)

where, RL = Remaining life in months PL = Number of plugged tubes allowed before condenser performance is affected PT = Number of plugged tubes to date GR = Growth rate of tube failures in number of failures per month Condenser design is such that there is typically excess surface area available in the form of extra tubes to allow as many as 10% of the tubes to be plugged without reducing the effective heat transfer capacity of the unit. [12]

11-4


11.2 Tube Material Selection [35] Available tube materials and their specifications are presented in the following four categories: x

Titanium Tubes for Critical Applications: Operating experience with titanium tubes indicates that the tubes are free from corrosion or cooling water erosion related failures over the range of condenser applications. The material is rated as superior in fresh, salt, and brackish water applications. Also, the experience with welded tube-to-tubesheet joints with titanium or titanium-clad tubesheets has been good. Titanium has a relatively low elastic modulus (15 E+6 psi) (103 E+6 kilopascal). Flow-induced vibration considerations require a closer tube support spacing for titanium tubes compared to tubes of other commonly used materials.

x

Modified Stainless Steels for Seawater Service: An austenitic stainless steel alloy, AL-6X, has been utilized with general good results in seawater-cooled condensers. The relatively high (29-30 E+6 psi) (200-207 E+6 kilopascal) elastic modulus of this stainless steel alloy allows the tubes to be utilized in retubing applications without changing the tube support spacing. Welded tube-to-tubesheet joints have not been used with modified stainless steel tubes.

x

Austenitic Stainless Steels for Cooling Tower Service with Freshwater Service Makeup: Type 304 and 316 austenitic stainless steels have been used in a number of applications with recirculating and once-through cooling water. Experience indicates that corrosion failures of types 304 and 316 stainless steel condenser tubes are not common in recirculating water systems with cooling towers, freshwater makeup, and chloride levels below 300 ppm. This service success has been attributed to aeration of the cooling water in the cooling towers. Some pitting or crevice corrosion failures have been experienced by stainless steel tubes (particularly type 316) in once-through cooling systems where moderate to high chloride, manganese, salt, or organic fouling is present. For maximum assurance of satisfactory performance, the conservative approach is to limit the use of type 304 and 316 stainless steel tubes to freshwater and freshwater makeup cooling tower applications. Welded tube-to-tubesheet joints have not been used for type 304 or 316 stainless steel tubes. This could be due to concern over tube weld shrinkage stresses in contact with chloride-containing cooling waters.

x

Copper-Alloy Tubes: A large number of condensers have used copper-alloy tubes with Admiralty brass tubes in freshwater service and aluminum bronze, aluminum brass, and copper-nickel tubes in saltwater, brackish water, and freshwater service. Corrosion performance has varied with these materials being sensitive to polluted applications. The ability of copper oxides to perform as an oxidizing species in steam generators has led to the replacement of copper alloys in PWRs and BWRs. Admiralty brass, aluminum brass, aluminum bronze, and arsenical copper tubes should not be used in air-removal sections to avoid corrosion from ammonia and carbon dioxide attack.

11-5


11.2.1 Titanium The specification requirements are: x

Tubes shall be made from a commercially pure titanium alloy in accordance with ASTM B 338 Grade 1 with a maximum oxygen concentration of 0.14%. The major differences between Grade 1 and 2 materials are the strength and oxygen content as shown below. Parameter

Grade 1

Grade 2

Minimum tensile strength, ksi (MPa)

35 (241)

50 (345)

Yield strength range, ksi (MPa)

25-45 (172-310)

40-65 (276-448)

Maximum oxygen content (%)

0.18

0.25

It should be noted that the lower oxygen content of ASTM B338 Grade 1 tubing provides additional ductility for expanding the tubes into the tubesheets. x

Seamless or welded tubes should be specified. If welded tubes are specified, the strip should be required to be in accordance with ASTM B265 Grade 1. Supplementary Requirement S-1 of ASTM B265 (Surface Requirement Bend Tests) should also be invoked.

x

The tube wall thickness must be specified. Presently used thicknesses for U.S. applications vary from 0.020 to 0.035 in. (635 to 889 Pm). Retubed units are sometimes limited to a wall thickness of 0.028 in. (711 Pm) or greater, depending on reuse of the existing tubesheets. Some condensers retrofitted with new tube bundles use titanium with a wall thickness of 0.020 in. (635 Pm). This is in addition to new condenser units using titanium tubes with a wall thickness of 0.020 in. (635 Pm). The non-destructive eddy current or ultrasonic tests of each tube should be in accordance with ASTM E213 for ultrasonic testing or with ASTM E243 for eddy current testing, except that the calibration notches must be in accordance with the tubing specification ASTM B338.

11.2.2 High Performance Stainless Steels [36] Beginning in the early 1970s, research and development initiatives within the stainless steel industry led to the development of a family of extremely chloride-resistant materials known as the high performance stainless steels. These grades were designed to use a combination of high chromium and molybdenum to provide economy and the ability to withstand severe corrosive service. One of the target applications was steam condenser tubing for power plants using seawater or brackish water for cooling. For this application, a group of alloy types emerged and is shown in Table 11-1.

11-6

EPRI Licensed Material Remaining Life, Materials, and Constructability [3,12] Table 11-1 High Performance Stainless Steel Tube Material [36] Common Name

Uniform Numbering System No.

Chromium (%)

Nickel (%)

Molybdenum (%)

AL-6X

N08366

Austenitic

Allegheny Ludlum

20

24.5

6.2

0.02

AL-6XN

N08367

Austenitic

Allegheny Ludlum

20

24.5

6.2

0.20

254 SMO

S31254

Austenitic

Avesta AB

20

18

6.2

0.20

654 SMO

S32654

Austenitic

Avesta AB

25

22

7.5

0.50

AL 29-4C

S44735

Ferritic

Allegheny Ludlum

29

-

4.1

0.01

0.4 Ti

SEACURE

S44660

Ferritic

Crucible Materials

27

2.2

3.7

0.01

0.4 Ti

290 Mo

S44375

Ferritic

Vallourec

29

-

4

-

0.4 Ti

Ferritic

Vallourec

29

-

3

0.4 Ti

0.4 Ti

29 Cr-3Mo

Type

Co. TradeMarks

Nitrogen (%)

Other (%)

0.8 Cu

None NuMonit

S44635

Ferritic

Avesta AB

25

4

4

FS10

S44800

Ferritic

Sumitomo Metal Ind.

29

2.2

4.1

0.01

Differences among these grades relate primarily to their structural types, austenitic or ferritic, and in nitrogen content. Both the structural and chemical composition differences affect certain properties important to condenser tube service. The newest of these grades, S32654, is distinctly different from the others. It has significantly higher corrosion resistance because of its high nitrogen content. All the other grades can be considered technically equivalent in terms of localized chloride pitting and crevice corrosion resistance. The specification requirements [35] are: x

AL-6X tubes shall be in accordance with ASTM B 676 (UNS-N08366), Class 2. A minimum annealing temperature of 2100 qF (1149qC), followed by a water quench should be specified to prevent a sigma phase rich in molybdenum from forming. Tensile and elongation tests in accordance with ASTM E 8 should be required for the strip used in manufacturing of the welded tubes. Either UT or ET should be specified. UT examination for both seamless and welded tubes should be in accordance with ASTM E 213, supplemented by ASTM E 273 for welded tubes.

x

Eddy current examination should be required to comply with ASTM E 426 or E 571. 11-7


x

SEA-CURE, NuMonit or AL 29-4 tubes shall be in accordance with ASTM A 268 and ASTM A 450. Stress relief at 1200qF (1149qC) should be specified for this ferritic material. Supplemental Requirement S-1 of ASTM A 268 should be invoked for these tubes to require an air leak test for each tube. Either UT or ET should also be specified. UT examination for both seamless and welded tubes should be in accordance with ASTM E 213 supplemented by ASTM E 273 for welded tubes. Eddy current examination for the ferritic material will require magnetic saturation and is covered by ASTM E 309.

11.2.2.1

Initial Installations

The first commercial condenser installation of a high performance stainless steel was in 1973 at the United Illuminating Bridgeport Harbor Station. The grade used was the original, lownitrogen version of the modern 0.20% nitrogen austenitic stainless steel, AL-6XN (NUS N08367). The plant is located on Long Island Sound and the cooling water is essentially seawater. After an initial period of evaluation extending to about 1977, other installations began with rapid escalation after 1980. Figure 11-1 shows the number of installations per year. Over 200 installations have been made through 1998. This represents nearly one hundred million feet of installed tubing. These installations include all of the stainless steels described in Table 11-1 and a variety of cooling waters ranging from heavily polluted seawater to clean freshwater.

Figure 11-1 High Performance Stainless Steel Installations [36]

11-8


11.2.2.2

Water Type Significance

Seawater and brackish water-cooled condensers were originally thought to be the prime areas of application for the high performance stainless steel tube materials. This was based on the good chloride resistance of these materials and the fact that materials such as Admiralty brass and type 304 stainless steel are generally considered suitable for handling fresh cooling waters. Technical reasons cited for Admiralty brass failures at freshwater sites include suspected sulfide pitting and, with type 304 stainless steel, under-deposit manganese pitting or microbiologically influenced corrosion. Type 304 can replace Admiralty Brass that is suffering sulfide pitting at a substantial cost saving compared to the high performance stainless steels. The reasons for using high performance stainless steels can be based on the perception that these are fail-safe choices. High performance stainless steel usage by water type is shown in Figure 11-2.

Figure 11-2 High Performance Stainless Steel Water Usage [36]

11.2.2.3

Tube-Related Problems

The five types of tube-related problems for the high performance stainless steels are tubesheet crevice corrosion, pitting corrosion, tubesheet galvanic corrosion, hydrogen cracking, and vibration fatigue. These failure mechanisms are discussed in Section 8.2 of this report. The data is shown in Figure 11-3.

11-9


Figure 11-3 High Performance Stainless Steels Problem Incidents [36]

Specific Cases of Tubesheet Crevice Corrosion: The high incidence of tubesheet crevice corrosion with an austenitic alloy involves five condensers at a utility that all have a similar tubesheet joint design and all operate on seawater. The unusual joint design is a gasketed joint with a type 316 stainless steel tubesheet. This type of joint had been successful at the utility with the previous type 316 stainless steel tubes that eventually failed by pitting. However, with the installation of the new, austenitic N08367 high performance stainless steel tubes, crevice corrosion of the tubesheet bore was noticed after periods of four to eight years in units at one plant site and after just a few months at another plant site. The corrosion was severe enough to require correction action. A tubesheet coating was applied at the less aggressive site and a combination of coating and cathodic protection was applied at the more aggressive site. Based on this experience, and the fact that gaskets are known to be initiators of crevice corrosion even in highly corrosion-resistant stainless steels, this joint design would not be advocated. These incidents should be treated as special cases of under-gasket crevice corrosion. If a stainless steel tubesheet is considered for use with the high performance stainless steel grades, the tubesheet should have corrosion resistance at least equal to that of the tube material.

11-10


Specific Cases of Tube Pitting Corrosion: Tube pitting corrosion has been reported at seven installations. All of these cases involve condensers where high-chloride brackish or seawater is used for cooling. In contrast, there have been no reports of pitting or any other form of corrosion at the freshwater sites. In all four cases involving an austenitic grade, the tube material is the original, low-nitrogen AL-6X. This 6% molybdenum stainless steel is known to have lower chloride-pitting resistance than its modern counterpart, AL-6XN, which contains a nitrogen content of 0.20%. Of the three cases involving the ferritic grades, two are with alloy SEA-CURE and one was with AL29-4C. The applications of SEA-CURE were in 1981 at Port Everglades #2 and in 1982 at Indian River #2. Based on the experience at Port Everglades, the original chemical composition was determined to be too lean and was subsequently enhanced with increased molybdenum and chromium. In addition, the possibility of a high tube wall temperature near a steam dump might also have contributed to the pitting at Port Everglades. The Indian River #2 site is unusual in that the cooling water chemistry produces severe inorganic fouling deposits. Pitting was not noticed until much later. The benefit of frequent cleaning in controlling pitting suggests that underdeposit corrosion and the original lean chemistry might account for the pitting at this site. The third case of pitting corrosion involving a ferritic high performance stainless steel occurred at the Northside #3 station with alloy AL 29-4C. Full penetration pits developed in three tubes with other pits present one year after startup in 1990. Suspected causes were excessive targeted chlorination, manufacturing oxide and defects, sulfate reducing bacteria and an extended down period without draining or flushing shortly after retubing. In the last few years the frequency of pitting has declined. A summary of each of these cases is provided in Table 11-2.

11-11

Seawater

Bridgeport Harbor #1

AL-6X

11-12

Seawater

Maine Yankee #1

Al-6X

Brackish

Northside #3

AL 29-4C

Seawater

Type of Cooling Water

Everglades #2

Station

SEA-CURE

Tube Material

25%

>10%

>3

3

Number of Tubes Affected

Table 11-2 Summary of Pitting Corrosion Problems [36]

Remaining Life, Materials, and Constructability [3,12]

Progressive pitting initially in welds and then general pitting confined primarily to the first 15 feet behind the inlet 10 years after startup.

Progressive pitting in many tubes with preference for the top section of the condenser 2 years after startup.

Full penetration pits developed in 3 tubes with other pits present one year after startup. Occasional pitting continued for about 7 years subsequently.

Full penetration pits developed at a mid-span location in 1 waterbox and nearby tubes showed pitting 1 year after startup.

Problem


No specific cause. Suggestions were that postweld tube annealing would have produced better weld corrosion performance.

Poor tube quality or chlorine from excessive cathodic protection.

Excessive targeted chlorination, manufacturing oxide and defects, sulfatereducing bacteria, and an extended down period without draining or flushing shortly after retubing.

Steam dump located near the problem location. Tube chemistry was normal although it was the original low Cr, low Mo composition for this grade.

Suspected Cause

Bridgeport Harbor #2

Calvert Cliffs #1

Indian River #2

AL-6X

SEA-CURE

Station

AL-6X

Tube Material

Brackish

Seawater

Seawater

Type of Cooling Water

5

5%

25%

Number of Tubes Affected

Table 11-2 (cont.) Summary of Pitting Corrosion Problems [36]

Under-deposit pitting corrosion occurred under severe deposits.

Crevice corrosion underdeposits and preferential to the weld seam 12 years after startup.

Progressive pitting initially in welds but then general pitting confined primarily to the first 15 feet behind the inlet 10 years after startup.

Problem


Infrequent cleaning.

Unknown.

No specific cause. Suggestions were that postweld tube annealing would have produced better weld corrosion performance.

Suspected Cause

11-13

Remaining Life, Materials, and Constructability [3,12]


11.2.3 Austenitic Stainless Steel [35] The specification requirements are: x

Type 304 stainless steel tubes shall be in accordance with ASTM A 249 for welded tubes and A 213 for seamless tubes (UNS-30400) and ASTM A 450. A minimum annealing temperature of 1900qF, followed by a water quench or by cooling by alternate means to 800qF in less than one minute, should be specified. Supplemental Requirement S-3 of ASTM A 249 should be invoked to require an air leak test for each welded tube. Either UT or ET should also be specified. UT examination for both seamless and welded tubes should be in accordance with ASTM E 213, supplemented by ASTM E 273 for welded tubes. ET should be in accordance with ASTM E 426.

x

Type 316 stainless steel tubes shall be in accordance with ASTM A 249 for welded tubes and A 213 for seamless tubes (UNS-31600) and ASTM A 450. Other requirements should be identical to those discussed above for Type 304 tubes.

11.2.4 Copper Alloys [35] The specification requirements are: x

70-30 Cu Ni tubes shall be in accordance with ASTM B 111 or B 543. The tubes should be specified to be in the annealed condition. Tensile tests and mill test reports should be required. ET in accordance with E 243 should be specified. If welded tubes are specified, both ET and pneumatic test requirements should be invoked.

x

90-10 Cu Ni tubes shall be in accordance with ASTM B 1121 or B 543. The tubes should be specified to be in the light drawn temper condition. Tensile tests and mill test reports should be required. ET in accordance with E 243 should be specified. If welded tubes are specified, both ET and pneumatic test requirements should be invoked.

x

Aluminum bronze tubes shall be in accordance with ASTM B 11 (C 60800). Tensile tests and mill test reports should be required. ET in accordance with E 243 should be specified. Welded tubes of this alloy should not be specified.

x

Aluminum brass tubes shall be in accordance with ASTM B 111 (C 68700). Tensile tests and mill test reports should be required. ET in accordance with E-243 should be specified.

x

Admiralty metal tubes shall be in accordance with ASTM B 111 (C 44300, C44400, or C 44500). Tensile tests and mill test reports should be required. ET in accordance with E 243 should be specified.

11-14


11.2.5 Summary of Material Specification [35] See Table 11-3 for a summary of condenser tube material specifications. Table 11-3 Condenser Tube Material and Testing Specifications [35] Tube Material Titanium

AL6X

Material Specification

Testing Specification

ASTM B338 Grade 1, 2 seamless

ASTM E 213 UT

ASTM B 265 Grade 1 welded strip

ASTM E243 ET

ASTM B 676 Class 2, UNS-N08366

ASTM E 213 UT

ASTM E-8 welded strip

ASTM E 426 or ASTM E 571 ET

SEA-CURE

ASTM A 268, UNS S44660

ASTM E 213 UT,

NuMonit

UNS S44635

ASTM E-273 weld

Al 29-4C

ASTM A 268, UNS S44375

ASTM E 309 ET

439 Stainless Steel

ASTM A 268, UNS 43035

304 Stainless Steel

ASTM A 249 welded, UNS S30400

ASTM E 213 UT,

ASTM A 213 seamless

ASTM E-273 weld

ASTM A 269

ASTM E 426 ET

ASTM A 249 welded, UNS S31600

ASTM E 213 UT,

ASTM A 213

ASTM E-273 weld

ASTM A 269

ASTM E 426 ET

ASTM B 111 seamless

ASTM E 243 ET

316 Stainless Steel

70-30 Cu Ni

ASTM B 543 (C 71500) welded 90-10 Cu Ni

ASTM B 111 seamless

ASTM E 243 ET

ASTM B 543 (C 70600) welded Aluminum Bronze

ASTM B 111 (C 60800)

ASTM E 243 ET

Aluminum Brass

ASTM B 111 (C 68700)

ASTM E 243 ET

Admiralty Brass

ASTM B 111 (C 44300, C 44400, C44500)

ASTM E 243 ET

11-15


11.2.6 Material Comparison [35] See Table 11-4 for a comparison of condenser tube materials. Table 11-4 Condenser Tube Material Comparison [35] Material Titanium

Advantages

Disadvantages

Superior corrosion resistance

High cost

Weldable tube-to-tubesheet joints for leak-tight integrity

Subject to hydriding if cathodic protection is not operating properly

AL-6X, AL-6XN

Excellent corrosion resistance

High cost

300 Series Stainless Steel

Very good corrosion resistance in low-chloride freshwater

Subject to various forms of under deposit corrosion and crevice corrosion

400 Series Stainless Steel

Very good corrosion resistance in low-chloride freshwater Better heat transfer coefficient than 300 series stainless steel

Cu Ni Alloys

Very good corrosion resistance in unpolluted water

Subject to severe corrosion in sulfide bearing water Subject to inlet end and blockage erosion

Aluminum Brass

Good corrosion resistance in unpolluted brackish or saltwater

Subject to inlet end and blockage erosion

Excellent heat transfer coefficient

Subject to condensate grooving

11.3 Tubesheet Joints and Material Selection [35] The four types of tube-to-tubesheet joints are: x

Expanded or flare joint

x

Expanded and grooved joint

x

Packed joint

x

Expanded and welded joint

Figure 11-4 shows a sketch of an expanded, expanded with grooves, expanded and seal welded, and packed tube-to-tubesheet joint.

11-16


Figure 11-4 Typical Tube-to-Tubesheet Joints (Courtesy of Expansion Seal Technologies)

11.3.1 Expanded Joint The expanded joint is obtained by expanding the tube inside the tubesheet hole. The tube is deformed, first elastically and then plastically, until it fills the hole, creating a compression fit. The axial strength of the joint and its leak integrity are provided by the compression fit of the tubesheet to the hole. Most operating condensers use expanded tube-to-tubesheet joints. Advantages of the expanded joint in comparison to a welded joint are that it is easy to form at original construction and allows condenser retubing with minimal effort. Depending on tightness requirements and material combinations, an expanded joint can also be re-expanded. This, however, might be difficult with titanium tubes. Disadvantages of the expanded joint are that it has less axial load carrying capability than an expanded and welded joint for currently used tubesheet thicknesses. It does not provide as positive a seal between condensate and cooling water as a welded joint. The expanded joint is also less tolerant to tubesheet hole out-of-roundness. Use of an expanded joint only with a carbon steel tubesheet clad with titanium can have a potential leak path between the circulating water

11-17


and carbon steel base material. This is dependent upon the thickness of the titanium cladding material. Over-expanding can result in tubesheet damage, excessive thinning of the tube wall, and work hardening of the material. Over-expanding can result in cracking of titanium tubes. A problem experienced with expanded joints has been tube pullout and subsequent leakage, especially at the initial hydrostatic test or plant startup. Factors that might contribute to tube pullout appear to be inadequate analysis of the tubesheet/flange, lack of acceptance criteria for joint loads, poor quality control of the expansion process, lack of proper cleanliness, and poor quality control of the tubesheet hole geometry. The expanded joint is usually formed by mechanical expansion. In mechanical expansion, a roller expander has roller bearings mounted in a cage that rotates at speeds of 400 to 1,000 rpm around a tapered mandrel. The mandrel is forced into the bearing cage, which causes each roller to move radially outward and expand the tube. Most roller expanders have three roller bearings, however, for stainless steel and titanium five roller cages are commonly used. Other techniques that might be used are hydraulic and explosive expansion. Hydraulic expansion is accomplished with a pressurized liquid, which expands the tube into the tubesheet. The length of tube expanded is determined by o-ring seals on the expansion probe. Explosive expansion is accomplished with an explosive charge that is placed in the tube and then remotely detonated. The force of the explosion expands the tube into the tubesheet to give a compression fit. 11.3.2 Expanded and Grooved Joint Machining one to two grooves into the tubesheet hole will improve the pullout strength of an expanded joint. With a single groove the allowable load can be increased up to 30% depending on the materials used. Two grooves might increase the smooth hole allowable by 40% for certain material combinations. A typical groove depth is 1/64 inch (3.8 mm). The mechanical pullout strength developed by a particular rolled joint does not necessarily reflect the capability of the joint to provide a seal between the condensate and the cooling water. Smooth pre-rolled tube holes have been found to be the best for high-pressure leak tightness and groove holes appear to develop the greatest pullout strength. 11.3.3 Packed Joint This design tube-to-tubesheet joint has an o-ring and a packing retainer between the tube and tubesheet. 11.3.4 Expanded and Welded Joint Most experience with welded tube-to-tubesheet joints involves fusion welding. The fusionwelded joint can be a strength weld that carries the entire joint load and performs the sealing function. Alternatively, the joint can be a seal weld that augments an expanded joint by 11-18


providing greater leak integrity but is not considered a load-carrying member. Tube and tubesheet materials preferable for welded joints are stainless steel and titanium. If titanium is used with a welded joint, the tubesheet must be titanium or clad with titanium. Key Technical Point The primary advantage of an expanded and welded joint is that it can provide greater axial strength and better leak integrity than an expanded joint for titanium and stainless steel tubes with tubesheets of weld compatible materials. To achieve a reliable welded joint there must be: x

Compatible tube and tubesheet materials

x

Tight control over the weld process parameters

x

A clean weld area

x

Control of the surrounding environment, that is, humidity

x

Reliable, qualified equipment, and qualified welders

Field repair of welded joints must be performed under the same cleanliness and environmentally controlled conditions as the original weld. Roller expansion in conjunction with welding should be done without lubricating oil. The lubricating oil gets into the space between the tube and the tubesheet where it cannot be removed. The presence of lubricating oil could result in weld porosity. Welded joints will complicate retubing because of the difficulties of grinding or machining out the tube to tubesheet welds. For this reason, welded tubesheet joints are recommended only for tube materials where there is a high confidence of satisfactory corrosion performance, that is, titanium for saltwater and stainless steel for freshwater service. 11.3.5 Joint Adhesives Anaerobic curing adhesives can be used to supplement expansion. When an adhesive is used to supplement expansion, it can increase the pullout strength. Anaerobic adhesives, such as Loctite®, will cure when oxygen is excluded. Surfaces to be bonded must be clean and free of oil or an oxide film. Adhesive bonding requires a higher degree of cleanliness than welding. 11.3.6 Material Selection [35] The condenser tubesheet material selection is based on the following criteria: x

Yield Strength: The tubesheet material should have a yield strength higher than the yield strength of the tube material to facilitate satisfactory expansion of the tubes into the tubesheet. 11-19


x

Electrochemical Potential: The tubesheet material should be relatively noble to minimize the requirement for cathodic protection.

x

Weldability: Where the tube-to-tubesheet joint includes a seal weld between tube and tubesheet, the tubesheet material must be weld-compatible with the tube material.

x

Machineability: The tubesheet material should be readily machinable to facilitate the drilling of the tube holes in the tubesheet. It is particularly important that the surface of the as-drilled holes be smooth and free of tool chatter.

x

Flatness: Tighter flatness tolerances are required with higher strength tubesheet materials for an acceptable tubesheet to waterbox flange joint. Weaker tubesheet materials such as Muntz metal, will readily conform to the waterbox flange. Flatness tolerances for materials such as stainless steel or titanium should be reduced to half of that previously specified for weaker materials.

A summary of the tubesheet material recommendations is shown in Table 11-5.

11-20

EPRI Licensed Material Remaining Life, Materials, and Constructability [3,12] Table 11-5 Tubesheet Material Recommendations [35] Tube Material Titanium

AL-6X

Sea-Cure

Tubesheet Joint Type

Tubesheet Material

Welded

Titanium

B 265 Grade 1, 2, 3

Expanded but not welded

Carbon Steel clad with Titanium

A 285, A 515 or A 516 clad with B 265 grade 1, 2 or 3

Expanded

Stainless Steel

A 240 TP 409, 410 or 316

Aluminum Bronze

B 171

Carbon Steel clad with Stainless

A 515 or A 516

Stainless Steel

A 240 TP 409, 410, 316

Expanded

Carbon Steel clad with Stainless Steel

AL 29-4C NuMonit Type 304 Stainless Steel

Type 316 Stainless Steel

70-30 Cu Ni 90-10 Cu Ni

Aluminum Bronze

Admiralty Metal

ASTM Specification

A 515 or A 516

Welded

Stainless Steel

A 240

Expanded

Stainless Steel

A 240

Aluminum Bronze

B 171


A 515 or A 516

Welded

Stainless Steel

A 240

Expanded

Stainless Steel

A 240

Aluminum Bronze

B 171


A 515 or A 516

70-30 Cu Ni

B 171

Aluminum Bronze

B 171

90-10 Cu Ni

B 171

70-30 Cu Ni

B 171

Aluminum Bronze

B 171

Muntz Metal

B 171

90-10 Cu Ni

B 171

70-30 Cu Ni

B171

Aluminum Bronze

B 171

Muntz Metal

B 171

90-10 Cu Ni

B 171

70-30 Cu Ni

B 171

Aluminum Bronze

B 171

Muntz Metal

B 171

Expanded Expanded

Expanded

Expanded

11-21


11.4 Waterbox and Shell Materials [35] Improper selection of waterbox and shell material could greatly accelerate galvanic corrosion and shorten condenser life. In many condenser applications, the waterbox is anodic relative to the tubes and tubesheet and provides some degree of cathodic protection to the tubes and/or tubesheet. For example, cast-iron waterboxes provide some degree of protection to copper-alloy tubes and tubesheet. This degree of protection will be reduced in-service as the cast-iron graphitizes and becomes less anodic. In general, carbon steel materials have provided satisfactory service for both shell and waterbox. Copper-nickel material has been utilized as a waterbox material or as a lining for the waterbox to reduce the rate of biological fouling of the waterbox. Other waterbox linings include rubber, coal tar, and epoxy coatings. Typical materials for shell and waterboxes are shown in Table 11-6. Table 11-6 Condenser Shell and Waterbox Materials [35] Materials

ASTM Specifications

Carbon Steel Plates

A-36, A-283, A-285, A-515, A516

Carbon Steel Bars, Pipe, and so on

A-36

Cast-Iron

A-48

Stainless Steel Plates

A-240 TP 304 and 316

70-30 Cu Ni

B-402

90-10 Cu Ni

B-402

11.5 Constructability Issues [25] There are usually two approaches to refurbishing a utility condenser. They are: x

A retubing approach - This involves replacing the tubes within the existing tubesheet and supports. Major material requirements include the tubes and anti-vibration tube stakes. It might be necessary to replace the tubesheet.

x

A rebundling approach - Existing tube bundles and possibly sidewalls are replaced with shop-fabricated modules. This approach permits the redesign of the tube bundle pattern, while minimizing the outage time necessary to complete the modification.

11.5.1 Retubing Pre-outage work for retubing and rebundling modifications include removal of grating and support steel, installation of electrical and air supply services, rigging and monorail preparation, and any interference equipment removal. The retubing approach requires the most outage time to remove individual tubes, taking care not to damage the tubesheets. The installation of new tubes with staking and wedging to correctly position the tubes is time consuming. The attachment of the tubes to the tubesheet is a critical process for leak-free joints. 11-22


For a retubing effort, procedures should be developed for the following tasks. The procedures should be approved by all parties involved, that is, the contractor, consultants, and the owner/operator. x

Waterbox removal and installation

x

Tube plug removal – see Section 10.1.4

x

Tube removal

x

Breaking tubesheet joints

x

Removing tubes

x

Tubesheet replacement

x

Support plate deburring

x

Tubesheet hole refinishing

x

Installing new tubes

x

Expanding tubes

11.5.1.1

Waterbox Removal and Installation

The station might have trolley beams or access to the turbine building crane designed for removal of waterboxes. If this is not the case, lift points must be selected at various steel members within the building. The structure should be reviewed to ensure its ability to take the loads. The lifting procedure should identify any beams that provide even load distribution during waterbox handling. Provisions for slings, shackles, turnbuckles, chain falls, come-alongs, blocks, air winches, and crane services should be identified. A description of the proper use of this equipment should be included in the procedure. Temporary structures and rigged equipment should be installed before shutdown. Removal of the waterboxes or waterbox covers should begin immediately after shutdown. Instrumentation should be removed to prevent damage. If used, impressed current cathodic protection system anodes should be removed. Circulating water pipe expansion joints should be removed prior to waterbox removal. Butterfly valves interconnecting waterboxes should be removed next. Miscellaneous connections can be removed simultaneously along with the previously discussed connections. The final connection to be broken should be the waterbox to tubesheet joint. Removal of old waterbox bolts is generally accomplished with an impact gun. Bolts that cannot be removed with an impact gun can either be burned off or removed with a hydraulic device. A good practice is to replace all old bolting with new materials. Due to corrosive build-up, the waterboxes might not move after all bolting is removed. A number of wooden wedges should be driven into the joint with sledgehammers until the waterbox is broken loose. 11-23


Waterbox flange gasket surfaces should be inspected for defects and repaired before reinstallation. Replacement rubber gaskets should be installed along with an appropriate caulking material for a good seal. Gaskets should be dove-tailed in corner areas. 11.5.1.2

Tube Removal

The process of old tube removal starts at shutdown and cooldown of the condenser. Crews are sent in to each waterbox to start removal of any tube plugs and tube inserts. The old tubes are cut free from the tubesheet on the end opposite the removal direction with an internal tube cutter. Tubes should be cut a minimum of 1/2 inch (1.3 cm) behind the steam side face of the tubesheet. An internal tube cutter is used to minimize distortion of the tube ends. The tool should incorporate a pneumatic drive and manual control of the blade feed. The cutter head is designed to have a front-end sized to fit into the inside diameter of the tube and a cutting blade of sufficient length to cut through the full wall thickness of the tube. During operation, the tool head rotates and the cutting blade is fed manually by either a lever arm or a steady pushing motion against the tubesheet to meet the inside diameter of the tube. A firm steady pushing force is applied by hand until resistance to cutting disappears, indicating the cut is complete. The lever arm and/or tool are then retracted and the tube cutter moved to the next tube. Cutting edges should be kept sharp, because a dull tool might create a burr on the tube that could damage the tubesheet hole during the removal process. When cutting time increases significantly or the cuts start to have rough edges, the cutting bits should be replaced. The tube removal process starts with the tube joint being broken. Approximately every fourth joint is broken and the associated tubes removed from the condenser. Tube stubs can be removed simultaneously as these operations are performed at the opposite end of the condenser. When all tubes have been removed from the tubesheets, inspection of tubesheet holes and support plate hole reaming should begin. Damaged holes should be reworked in accordance with the appropriate tubesheet hole refinishing procedure discussed in Section 11.5.1.7 of this report. The number of simultaneous cutting operations per tubesheet is a function of waterbox access and design. Distortion of the tubesheet can occur as the tubes are cut free because the tubesheet is structurally supported by the tubes. 11.5.1.3

Breaking Tubesheet Joints

The tube joints are broken by a hydraulic tube extraction device. The device is sized for the inside diameter and wall thickness of the specific tubes. The device is operated by inserting the head into a tube and actuating it, causing the draw bar to exert a radial force and engage the teeth with the tube. As the device retracts, it pulls the tube out approximately 4 in (10 cm) from the tubesheet. This breaks the roll to the tubesheet. Releasing the trigger of the device frees the draw bar and the machine can then be moved to the next tube. Due to the size of the extraction tool,

11-24


approximately every fourth tube joint is broken and the tubes removed. The number of simultaneous pulling operations is a function of tubesheet width and height. 11.5.1.4

Removing Tubes

After the tube-to-tubesheet joint has been broken, the tubes are removed from the condenser by means of a hydraulically driven extractor. The extractor functions by placing individual tubes projecting approximately 4 in (10 cm) from the tubesheet into the extractor opening. An internal set of gears grabs the tube and pulls it through the extractor flattening the tube to a ribbon as it is pulled. The flattened tube can then be fed into a tube chopper where the ribbon is cut into approximately 4-inch (10 cm) long pieces, thereby facilitating removal of scrap. Friction between the tubes and support plates should be reduced by lubrication. One method of lubrication is the use of garden sprayers or a garden hose inside the condenser to wet the tubes. The finer the spray, the better the lubrication is. In addition to spraying water on top of the tube bundles, individual tubes can be removed in the core of the bundles and perforated tubes installed in their place. Water supply hoses can then be connected to the tubes to insure complete wetting of the bundle. Key Human Performance Point Recent improvements in technology have resulted in tooling that can pull an entire tube and chop the tube into pieces in a single operation at the tubesheet. This improvement is significant because it reduces both the labor and space required for tube removal. The procedure of pulling tube stubs from the tubesheet is identical to that used for pulling tubes with one exception. As the machine is removed from the tube hole, the stub left from the cutting process must be removed from the machine tip manually and discarded. 11.5.1.5

Tubesheet Replacement

If the tubesheets are to be replaced, the inlet and outlet waterboxes require removal. Should removal space be a problem, the waterboxes opposite the tube removal direction need only to be removed a sufficient distance to replace the tubesheet (this includes access and rigging clearances). Tube plugs and tube inserts should be removed as both ends of the tubes are cut free from the tubesheets using internal tube cutters. The tubesheets can then be removed from the shell expansion joint (if installed). The expansion joint (or diaphragm) should be held in position prior to removal of the tubes and tubesheets by means of blocking and welding of the alignment plates. As with the waterbox removal, wooden wedges might be required to pry the tubesheet loose. Caulking and dovetailing are necessary for the new tubesheet-to-shell flange gasket. Before tightening bolts, the new tubesheet should be checked for hole alignment. Prior to tightening the new tubesheet bolts, a number of tubes should be inserted in all sections of the tubesheet to ensure that the holes are in reasonable alignment with the support plate holes.

11-25


11.5.1.6

Support Plate Deburring

Support plate holes are designed to be larger than the nominal tube outside diameter. During operation of the condenser, a considerable amount of corrosion product accumulates in the crevice between the tube and support plate. The net effect is that the clearance is reduced to virtually zero. Usually this corrosion product remains even after removal of the old tubes. To retube the condenser, the corrosion product should be partially removed by reaming. The reaming operation should start as soon as the tubes have been removed because several hundred thousand holes might have to be reamed. An early start can prevent the operation from becoming critical path. The number of people employed in this operation is a function of condenser shell access and available tooling. Reaming should be performed using pneumatically driven, spherical carbide burrs. As the burrs will become smaller through use, the burr diameters should be checked at least twice a shift to ensure that they have not become too small. The burrs need only pass quickly in and out of each support plate hole. Additional working of holes is labor intensive and might result in unwanted hole enlargement. 11.5.1.7

Tubesheet Hole Refinishing

Tubesheets are sometimes damaged as the old tubes are extracted. The damage appears as axial gouges or scratches in the tube holes. Because these gouges might be several thousandths of an inch (0.002-0.003 inch) (51-76 µm) deep, they can provide a water to steam path leakage path. After the tube removal process, the tubesheet should be thoroughly inspected and holes with damage should be identified. These holes shold be buffed with flapper wheels or wire brushes, taking care not to oversize the tubesheet holes. The condenser equipment specification should address oversize tubesheet holes as follows: x

An over-tolerance up to a maximum of 0.006 inch (152 µm) is acceptable for up to 4% of the total holes but the cause of holes in this range must be investigated and corrected before any further drilling.

x

Holes exceeding the number of size tolerances discussed above must be repaired or plugged and not used in the absence of test data demonstrating the adequacy of expanded joints in the holes.

Maximum allowable hole sizes are specified in HEI standards and are shown in Table 11-7. Should the leakage paths remain, reaming or plugging might be necessary.

11-26

EPRI Licensed Material Remaining Life, Materials, and Constructability [3,12] Table 11-7 Tubesheet Hole Size Limits [6] Nominal Tube Outside Diameter in Inches (mm)

Lower Limit in Inches (mm)

Upper Limit in Inches (mm)

5/8 (15.9)

0.632 (16.0)

0.641 (16.2)

3/4 (19.0)

0.758 (19.2)

0.767 (19.5)

7/8 (22.2)

0.883 (22.4)

0.892 (22.6)

1 (25.4)

1.008 (25.6)

1.018 (25.9)

1-1/8 (28.6)

1.138 (28.9)

1.148 (29.2)

1-1/4 (31.7)

1.263 (32.1)

1.273 (32.3)

1-3/8 (34.9)

1.388 (35.2)

1.398 (35.5)

1-1/2 (38.1)

1.513 (38.4)

1.523 (38.7)

1-5/8 (41.3)

1.639 (41.6)

1.651 (41.9)

1-3/4 (44.4)

1.764 (44.8)

1.776 (45.1)

1-7/8 (47.6)

1.889 (47.9)

1.901 (48.3)

2 (50.8)

2.016 (51.2)

2.028 (51.5)

The tubesheet hole should be serrated when expanding titanium or high-alloy, pit-resistance steel tubes into tubesheets with material of lower yield points such as Muntz metal. If the existing tubesheet already has grooves, re-grooving might be necessary to remove corrosion. 11.5.1.8

Installing New Tubes

Prior to tube insertion every 110th tubesheet hole should be measured and recorded. Similarly, tube wall thickness should be measured and recorded for all tubes to be inserted in benchmark holes. In some cases the variation in tube wall thickness is so small (less than + 0.0005 inch (12.7 µm) that, instead of measuring tube wall thickness, a single representative value can be utilized. Titanium and high-alloy pit-resistant steel tubes are thin-walled (typically 0.020 – 0.028 inch) (508 – 711 µm). These tubes require special handling to ensure that they are not crimped or permanently distorted. It is recommended that manufacturer’s storage and handling requirements be reviewed thoroughly and specific recommendations be incorporated into the tube installation procedure. Prior to tube insertion, the tubesheet holes should be washed with water. Tubes should be removed one at a time from the shipping box in the retubing area. A tube pilot or bullet is then inserted into each tube. Personnel inside the condenser should guide the first few rows of tubes because the tubes are very flexible and might not go directly through the correct support plate holes. It is always advisable to have personnel inside of the shell to help with tubes that hang-up in the support plates. It is critical that the tubes be inserted in line with the tube holes. Adequate scaffolding should be provided inside the condenser. The new tubes inserted into the condenser should never be used as a work platform or walked upon.

11-27


Key Human Performance Point Sufficient labor should be planned for tube insertion. Good practice is to provide one worker for each 10 feet (3 meters) of tube to be inserted. If a tubesheet is removed, the tubes should be pushed through the tubesheet at the opposite end and then the tubesheet should be reinstalled flush with the tube inlet side. If the inlet end of the tubesheet had previously been flared and the existing tubesheet is not going to be replaced, it is important to ensure that the tubes are installed flush with the tubesheet. Installation beyond this point will decrease the surface area contact and compromise the tube-totubesheet joint integrity. It is important that the locations of the various heat numbers in the condenser be recorded. This is best accomplished on tubesheet maps located on the tube pushing platforms. 11.5.1.9

Expanding Tubes

When all tubes have been inserted and both tubesheets are in place, the waterboxes should be bolted in place. Although the addition of the waterbox will make tube expansion more difficult in certain areas of the waterboxes, it is recommended before rolling the tubes to the tubesheet. This is to make the entire tubesheet stiffer and to reduce distortion of the tubesheet during the rolling process. Clusters of tubes at both ends, scattered over the entire cross-section, should be expanded to support the tubesheets and minimize tubesheet bowing. Each tube to be expanded should be lubricated with a suitable water-soluble lubricant. Expansion of the tubesheet can be accomplished in any desired sequence. Prior to expansion of the opposite tubesheet, the clusters previously described must first be expanded in order to minimize distortion. Expansion can then be performed in any desired sequence. As the expansion process proceeds, expanders should be kept in water and rotated every 100 tubes. Additionally, expanders should be checked for wear every 500 tubes. Control of expansion should be effected by monitoring apparent wall reduction. Apparent wall reduction should be calculated after expanding a maximum of 100 tubes per operator. Before starting the retubing, a pullout test should be performed in order to determine the range of apparent wall reduction that will produce the required tube-to-tubesheet joint strength for the combination of tube and tubesheet materials being utilized. The range of apparent wall reduction achieved during the retubing should fall within the range determined by pullout testing. Torque control should generally not be used as the primary control parameter for tube expansion. However, certain combinations of tube/tubesheet materials such as titanium and Muntz are very difficult to control within a desirable apparent wall reduction range. When expanding such a combination of materials, torque control must be used as the primary control criteria, while utilizing apparent wall reduction as a check to determine if the tube end expansion is trending either too high or low.

11-28


11.5.2 Rebundling A rebundling design constraint is that the turbine and concrete foundations are fixed. The modular replacement bundle should be optimized based on tube density and tube size. The tube size selected is usually between 7/8 and 1 1/4 inch (2.2 and 3.2 cm). The optimum layout is dependent on specific design conditions and economic factors. The ratio of the total nominal tube cross-sectional area to the total shell cross-sectional areas between the top and bottom of the bundle should be no more than 0.30 and preferably 0.25 or less. The desired limiting ratios based on the original and new condensers should be included in the replacement specification so that an informed decision can be made if the ratio cannot be satisfied. Space limitations often make it impossible to adhere to these limits. For example, bundle heights are limited by space required for steam flow, feedwater heaters, extraction piping, structural members, etc. in the condenser neck and by the water storage deaeration space, spargers, and so on. In the hotwell, the bundle height can be increased by permitting a reduction in tube density by relocating heaters outside the condenser. Key Technical Point In a rebundling approach, the tube spacing can be reduced with an increase in the number of tubes. This increase in tube side flow area generally results in reduced condenser circulating water pressure drop and an increase in circulating water discharge from the existing circulating water pumps. The resulting total circulating water flow to the rebundled condenser is higher. Generation might be increased with a more efficient design. In rebundling, the required leak-tight integrity must be established for the remaining equipment life. The leak-tight condenser will improve equipment availability. A rebundling approach can offer the following advantages compared to a re-tubing approach: x

Replacement of the tubesheets with a material compatible with the tube materials eliminates the need to coat the tubesheets and avoids galvanic corrosion of the tubesheet.

x

The bundle design can be changed for improved plant performance. This affords an opportunity to increase heat transfer area and improve turbine performance, with a possible increase in condenser efficiency.

x

Reduced unit outage time due to faster installation.

x

Shop fabrication with improved quality control.

x

A tighter condenser with less potential for condenser leaks. With a change in tubesheet material, the tube joints can be rolled and seal welded.

x

Placement of intermediate tube supports to eliminate the need for tube staking. This is often required with the thinner gauge tubes and materials with a lower modulus of elasticity.

11-29


12 REFERENCES

1. Thermal Performance Engineering Handbook,Volume II. EPRI, Palo Alto, CA: November 1998. TR-107422-V2. 2. Thermal Performance Engineering Handbook, Volume I. EPRI, Palo Alto, CA: October 1998. TR-107422-V1. 3. Condenser In-Leakage Guideline. EPRI, Palo Alto, CA: January 2000. TR-112819. 4. ABC’s of Condenser Technology. EPRI, Palo Alto, CA: August 1994. TR-104512. 5. B.K. Long, “Air Binding and Condenser Optimization.” Alabama Power Company, November 1996. 6. Heat Exchange Institute, Inc., Standards for Steam Surface Condensers, Eighth Edition, January 1984, and Ninth Edition, 1995. 7. ANSI/ASME Performance Test Code for Steam Condensers. ANSI/ASME PTC.12.2-1983, ASME, New York, 1983. 8. R.Putman and D. Karg, “Monitoring Condenser Cleanliness Factor in Cycling Plants,” Proceedings of the International Joint ASME/EPRI Power Generation Conference (IJPGC), San Francisco, CA (July 26–29, 1999). 9. Donald Q. Kern. Process Heat Transfer. McGraw Hill, New York 1990. 10. Preventive Maintenance Basis, Volume 34: Main Condensers. EPRI, Palo Alto, CA: July 1998. TR-106857-V34. 11. G. Katragadda, J.T. Si, D. Lewis, G.P. Singh, (Karta Technology, Inc.), J. Tsou (EPRI), “Condenser Performance Improvement using Heat Exchanger Workstation–Condenser Application,” Proceedings of the 1998 Heat Rate Improvement Conference, EPRI, Palo Alto, CA (September 1998). TR-111047. 12. High-Reliability Condenser Application Study. EPRI, Palo Alto, CA: November 1993. TR-102922. 13. R.J. Bell and Y.G. Mussalli, “Instrumentation and Techniques for Condenser Performance Monitoring,” Joint ASME/ANS Conference in Portland, Oregon (July 1982). 12-1

EPRI Licensed Material References

14. Condenser Macrofouling Control Technologies. EPRI, Palo Alto, CA: June 1984. CS 3550. 15. Condenser Microbiofouling Control Handbook. EPRI, Palo, Alto, CA: October. TR-102507. 16. On-Line Condenser Fouling Monitor. EPRI, Palo Alto, CA: December 1996. AP-101840V4P5. 17. Design Guidelines for Targeted Chlorination with Fixed Nozzles. EPRI, Palo Alto, CA: August 1992. TR-101096. 18. Fatora, S.J., Jones, S.D., Petro, J.R., Increasing Generating Capacity Through Improvement of Heat Removal Capacity, 1999. 19. G.E. Saxon, Jr. and R.E. Putman, “Improved Condenser Performance Can Recover Up to 25 Mw Capacity in a Nuclear Plant,” EPRI Nuclear Plant Performance Conference (August 1995). 20. G.E. Saxon, Jr., R.E. Putman, R. Schwarz, “Diagnostic Technique for the Assessment of Tube Fouling Characteristics and Innovation of Cleaning Technology,” EPRI Condenser Technology Symposium (1996). 21. Infrared Thermography Developments for Boiler, Condenser and Steam Cycle. EPRI, Palo Alto, CA: December 1997. TR-109529. 22. Condenser Leak-Detection Guidelines Using Sulfur Hexafluoride as a Tracer Gas. EPRI, Palo Alto, CA: September 1988. CS-6014. 23. R.B. Gayley, “Condenser In-Leakage Reduction,” EPRI Condenser Technology Seminar, Charleston, SC (August 30-31, 1999). 24. Recommended Practices for Operating and Maintaining Steam Surface Condensers. EPRI, Palo Alto, CA: July 1987. CS 5235. 25. “Condenser Retubing, Rebundling and Performance Modification,” 1999 EPRI Condenser Technology Seminar, EPRI, Palo Alto, CA (September 1-3, 1999). 26. Condenser On-Line Leak-Detection System. EPRI, Palo Alto, CA: December 1995. AP101840-V3P2. 27. Corrosion of Condenser Materials. EPRI, Palo Alto, CA: January 1993. AP-101588. 28. B.P. Boffardi, “Control the Deterioration of Copper-Based Surface Condensers,” Power Magazine. (July 1985). 29. Dickinson, Wayne H., Miller, Larry. Manganese-Dependent Corrosion in an Open Service Water System.

12-2

EPRI Licensed Material References

30. Krzywosz, Kenji. Condenser Assessment by Eddy Current Method, EPRI, Palo Alto, CA, August 1999. 31. Balance-of-Plant Heat Exchanger Condition Assessment Guidelines. EPRI, Palo Alto, CA: July 1992. TR-100385. 32. In-Situ Coating of Condenser Tubes as an Alternative to Retubing. EPRI, Palo Alto, CA: September 1997. TR-107068. 33. Condenser Retubing Criteria Manual. EPRI, Palo Alto, CA: May 1982. NP-2371. 34. Krzywosz, Kenji. Condition Assessment and Inspection Program for Reducing Heat Exchanger Tube Leaks, EPRI, Palo Alto, CA: June 2000. 35. Design and Operating Guidelines for Nuclear Power Plants. EPRI, Palo Alto, CA: September 1991. NP-7382. 36. C. Kovach, “Report on Twenty-Five Years Experience with High Performance Stainless Steel Tubing in Power Plant Steam Condensers,” 1999 EPRI Condenser Technology Seminar, EPRI, Palo Alto, CA: (September 1-3, 1999).

12-3


13 ACRONYMS

ASME

American Society of Mechanical Engineers

BAT

Best Achievable Technology

BCT

Best Conventional Technology

BPT

Best Practicable Technology

BTU

British Thermal Units

CCC

Criteria Continuous Concentration

CMC

Criteria Maximum Concentration

DO

Dissolved Oxygen

ET

Eddy Current Testing

EPRI

Electric Power Research Institute

FT

Feet

FMAC

Fossil Maintenance Application Center

GPD

Gallons per day

GPM

Gallons per minute

HEI

Heat Exchange Institute

HR

Hour

ID

Inside Diameter

INPO

Institute of Nuclear Power Operations

IRT

Infrared Technology

13-1

EPRI Licensed Material Acronyms

JIT

Just in Time

LER

Licensee Event Reports

MIC

Microbiologically Influenced Corrosion

MT

Magnetic Particle Testing

Mwe

Megawatt Electric

NDE

Non-Destructive Examination

NMAC

Nuclear Maintenance Applications Center

NPDES

National Pollutant Discharge Elimination System

NPSH

Net Positive Suction Head

NRC

Nuclear Regulatory Commission

O&MR

Operation and Maintenance Reminder

OPEC

Operating Plant Experience Code

OD

Outside Diameter

OE

Operating Experience

PDM

Predictive Maintenance

PM

Preventive Maintenance

PPB

Parts per Billion

PSI

Pounds per Square Inch

PT

Liquid Penetrant Testing

SCFM

Standard Cubic Feet per Minute

SEE-IN

Significant Event Evaluation Information Network

SEN

Significant Event Notification

SER

Significant Event Report

SF6

Sulfur Hexafluoride Gas

13-2

EPRI Licensed Material Acronyms

SJAE

Steam Jet Air Ejector

SOER

Significant Operating Experience Report

TEMA

Tubular Exchanger Manufacturer Association

TTD

Terminal Temperature Difference

UT

Ultrasonic Testing

VT

Visual Inspection Testing

13-3


14 GLOSSARY

Air Binding – the displacement of steam in the condenser with excess air that hinders the heat transfer process. Backpressure – the amount of vacuum measured at the turbine outlet to the condenser. Backpressure is usually measured in inches of mercury. Biocides – chemicals that are toxic to organisms. Biocides are grouped in two categories: oxidizing and non-oxidizing. Biofouling – the accumulation of microorganisms on the cooling water tube surface that impedes water flow, reduces heat transfer, and aids in corrosion. Brush and Cage System – an on-line tube cleaning system that shuttles a captive brush inside the tube by reversing the direction of cooling water through the condenser. Cathodic Protection – a water side corrosion control method that uses sacrificial anodes attached to the waterbox. Condenser On-Line Leak Detection System – (COLDS) – the EPRI-patented system that uses targeted injection of sulfur hexafluoride to detect and locate condenser tube leaks while the unit is in full operation. Frazil ice – the initial crystal from which ice develops in water bodies. Hotwell – the bottom of the condenser shell that is used as a condensate reservoir. It can be connected to the shell or an integral part of the shell. Infrared Technology (IRT) – the use of an infrared camera to detect hot and cool areas. This is one method used in detecting air in-leakage. Liquid Ring Vacuum Pump (LRVP) – mechanical pump used in the air-removal system of the condenser. The liquid ring vacuum pump is a rotary, positive displacement pump that uses a liquid as the principal element in gas compression. Pop Outs – bold lettered boxes in EPRI NMAC guides containing key human performance, operating and maintenance cost, and technical information. Macrofouling – the blockage of condenser tubes by organic or inorganic debris such as sticks, leaves, fish, mussels, and so on. 14-1

EPRI Licensed Material Glossary

Microfouling – the accumulation of inorganic scales or organic growths that deposit on the inside of condenser tubes. Multisensor Probe (MSP) – an instrument located in the exhauster vacuum line that measures the amount of air in-leakage. Non-oxidizing Biocides – systemic poisons that kill microbiological organisms by interfering with their metabolism. Oxidizing Biocides – poisons that kill or deactivate microorganisms by oxidizing the organic component of the microorganisms. Sparging – introducing steam into the condensate just above the hotwell level by use of steam nozzles. The sparging system functions mostly during reduced power operation and startup to reheat the condensate. Sponge Ball System – an off-line tube cleaning system that uses the cooling water flow to push or force slightly over-sized sponge rubber balls through the condenser tubes. The wiping action of the balls against the inner tube surface cleans the tube. Steam Jet Air Ejector (SJAE) – equipment that uses the viscous drag of a high-velocity steam jet for the ejection of air and other non-condensables from the condenser compartment. It is necessary to use several ejectors to obtain a sufficient vacuum. Subcooling – the cooling of the condensate below the saturation temperature corresponding to the condenser pressure. Condensate subcooling is caused by flooding the lower levels of condenser tubes with condensate. Hotwell subcooling occurs when the cooling water temperature is so low that it causes a moisture decrease at the turbine blade outlet. Technical Advisory Group (TAG) - a group composed of utility contacts, vendor representatives and consultants that provide technical review and oversight for EPRI developed products. Terminal Temperature Difference (TTD) – the difference between steam temperature and outlet cooling water temperature. Tracer Gas Testing – a leak detection method used on a sealed container that requires a pressure differential to exist between the interior and exterior of the component being tested. The tracer gas is placed in the area of higher pressure and migrates through leakage paths to the lower pressure area. Travelling Water Screens – a moving screen located before the circulating water pumps that prevents large organic and inorganic material from entering the intake. Tubesheet – a non-rigid structural member that holds the condenser tubes. The tubesheet consists of several plates with holes drilled for tube installation. The plates at the end of the tubes have a joint sealing arrangement.

14-2

EPRI Licensed Material Glossary

Waterbox – a plenum for cooling water entering and exiting the condenser tubesheet. The waterbox is typically bolted to the condenser with the tubesheet between the waterbox and condenser flange.

14-3


A SURVEY RESULTS

A survey was sent in August 2000 to the member NMAC and FMAC power plants for detailed information on their respective condenser equipment. The intent of the survey was to gather information that could be used by plant personnel that have similar equipment. The results of the survey are listed separately for the nuclear and fossil plants and are shown here in Appendix A.

A-1

A-2

Survey Results



A-3

Survey Results

A-4

Survey Results



B MECHANICAL TUBE CLEANING PROCEDURE

The following is an off-line tube cleaning procedure developed by Conco Systems, Inc. A Confined Space Permit might be required when working in the waterbox. Prepare Condenser 1. Drain and open waterbox and clean off tubesheet. 2. Verify safe atmosphere and temperature in waterboxes. 3. Install low-voltage lights for both ends of condenser. 4. Verify safe atmosphere and temperature in waterboxes. 5. Install floorboards if needed. 6. Install scaffolding in inlet waterbox if needed or have scaffolding close by to use when needed. It is best to shoot in direction of cooling water flow. 7. Hang tarp approximately 2 to 5 feet (60.1 cm to 1.5 m) away from tubesheet in outlet waterbox. 8. Cover all drains and openings to prevent loss of cleaners. 9. Post all safety signs, barriers, and tags. Prepare System 1. Verify availability of approximately 200 to 300 psi (1.4 to 2 megapascals) water pressure at 35 gallons per minute (2.2 liter/second) for each water gun being used. Hook up guns to water source; eliminate all leaks and/or restrictions in lines. 2. Water source can be plant’s water, condensate water, or ash sluice system. Portable Booster Pump can increase water pressure to required 200-300 psi (1.4 to 2 megapascals). 3. Recommended hose to the gun must be 800 psi (5.5 megapascals) working pressure, with pressed on 3/4 inch (1.9 cm) outside diameter National Pipe Thread fittings. 4. Install guns at swivel base 3/4 inch (1.9 cm) National Pipe Thread female fitting using the 3/4-inch (1.9 cm) hose (the combination of the swivel and hose reduces wrist fatigue for the shooter). B-1

EPRI Licensed Material Mechanical Tube Cleaning Procedure

5. NEVER USE AIR PRESSURE. NEVER USE QUICK DISCONNECT HOSE CONNECTIONS. Shooting the Condenser 1. Test 5 to 10 cleaners before loading a large amount. Make sure tube cleaning system is in working order and cleaners are correctly sized. 2. Insert cleaners in tubes. (a) It is best and fastest to load as many cleaners as possible and then shoot with as many guns as possible (2000 to 3000 tube cleaners or 25% to 50% of the total number of tubes per waterbox). 3. Insert gun behind cleaner and lock gun into tube by pushing gun straight in and cocking down and to the side, all in one complete motion. Hold gun firmly in cantilevered position and pull trigger. 4. Cleaners travel at about 10 to 20 feet per second (3 to 6 m/s). If these times are not met, check hoses and water supply for restrictions or tubes might be very badly fouled. 5. Make sure cleaners go all the way through the tubes. This is done by watching a gauge at the front of the gun. As the cleaner exits the tube, the gauge should show a pressure drop. If the pressure does not drop or climbs to line pressure, the tube might be dented or totally clogged. Checking Tubes 1. After all the tubes have been shot, check all tubes with a high intensity light. Hold a light at one end and have someone at the other end looking through the tubes. If one is blocked, a faint light or no light at all will be seen. Mark these tubes and re-shoot. (a) Re-shoot using only one gun to obtain the highest-pressure possible. (b) Re-shoot obstructed tubes using water pump set at higher pressure. (c) Rod out any obstructed tubes using flexible fiberglass rod. Clean Up and Storage 1. After the job is completed; (a) Wash off cleaners, air dry, and store properly. (b) Remove all debris from waterbox. (c) Wash down floors of waterboxes. (d) Clean up work area. (e) Sign off. B-2


C TUBE PLUGGING PROCEDURES

From Table 10-1, Tube Plug Data, the following tables are a listing of the corresponding tube plug installation procedures. These are the current procedures given by the manufacturer. It is advisable to check with the manufacturer for any changes or updates to these procedures when installing the tube plugs. Atlantic Group Brass and Fiber Jacketed Tube

Figure C-1 Atlantic Group Tube Installation for Flared and Straight Tube Ends Table C-1 Installation Procedures for the Atlantic Group Brass and Fiber Jacketed Tube Plug 1. Drive plug into position using a flat piece of wood (such as a 2 inch by 4 inch (5.1 cm by 10.2 cm) board) or round stock (such as a wooden dowel) that will fit squarely over the entire face of the plug. This will ensure that the fiber and brass are driven together. DO NOT DRIVE THE BRASS CARTRIDGE ALONE. The round stock should be only slightly smaller than the tube inside diameter. 2. For non-flared tube ends, plugs should be installed flush with the tubesheet. See Figure C-1. If, however, the fit is too tight, the plug can extend up to 1/4 inch (6 mm) beyond the tubesheet. If the fit is too tight and the plug cannot be installed within 1/4 in. (6 mm) of the tubesheet, contact the supplier for a smaller size plug. Note that outlet end tubes often extend beyond the tubesheet face; therefore, the plug must be recessed within the tube in order to be flush with the tubesheet. For flare tube ends, drive the plug approximately 1/8 in. (3 mm) beyond the tube end or tubesheet face. See Figure C-1. 3. Silicone can be used to cover the brass cartridge should cathodic problems be anticipated. Caution: Plugs are supplied to fit a particular tube gage or other tolerance as specified in the order. For the plug to seal properly, it should freely fit 1/8 in. (3 mm) to one-half its length into the tube or tubesheet hole before being driven.

C-1

EPRI Licensed Material Tube Plugging Procedures

Bemark Associates, Inc. K-Span Plug

Figure C-2 Bemark Associates K-Span Plug Table C-2 Installation Procedures for the Bemark Associates K-Span Plug 1. Clean the tube end or the tubesheet hole by wire brushing. 2. Clean any scale or debris from the tube end or the tubesheet hole. 3. Insert the largest tube plug gauge that will fit into the hole. The largest tube plug gauge that fits into the hole indicates the size of the plug to be installed. 4. Select the appropriate plug and insert the plug into the hole as far as the plug can be inserted. The shoulder of the plug should be flush against the tube end or the tubesheet face. 5. With a socket or a crescent wrench-tighten the expander nut until it reaches its mechanical stop. 6. Test the plug to ensure that the plug has sealed the tube or tubesheet, if possible. Note: The plug is designed to operate with a mechanical insertion stop and a mechanical expansion stop. Failure to insert the plug fully into the hole or failure to expand the plug to the fullest expansion might cause the plug to leak. If the plug fails to seal the leak, remove the expander nut and drive the expander out of the back of the expansion body. Remove the expander body, and then remove the expander. Inspect the hole, clean as required, and repeat the installation with the largest plug that can be installed.

C-2


Conco Systems, Inc. High Confidence, Expanding, Fiber, Pin, and Pin and Collar Tube Plugs

Figure C-3 Conco High Confidence Tube Plug Table C-3 Installation Procedures for the Conco High Confidence Tube Plug 1. Clean and dry the tube ends to be plugged. Always plug both ends of the tube. Both ends of tubes must be properly plugged to prevent stagnant water and/or leaks, which cause further problems. 2. Tighten nut finger tight to give snug fit in the tube. 3. Insert Conco High Confidence Tube Plug; seal cylinder end first into the tube. Locate grips as far back as possible on the tubesheet and clear of tube rolling transitions. The grips must engage the tube backed by the tubesheet in a parallel movement to assure maximum gripping action. 4. Tighten nut on bolt using a screwdriver and box wrench to point where the screwdriver is no longer required. 5. Torque nut to 50-inch-pounds (5.6 N-m) using a snap-on torque wrench of a 30–200 inchpounds (3 – 23 N-m) range and a deep well socket. 6. Move on to the next tube. 7. After approximately fifteen minutes, following original tightening, re-torque all plugs to the recommended torque or 50-inch-pounds (5.6 N-m). Torque further as needed for site-specific applications. Torque ranges of 50 to 100 inch-pounds (5.6 –11 N-m) should satisfy all applications. 8. Installation is now complete. For installations without lock nuts, Conco suggests the use of Loctite adhesive to hold the nut in place.

C-3


Figure C-4 Conco EX-3 Expanding Tube Plug Table C-4 Installation Procedures for the Conco EX-3 and EX-4 Expanding Tube Plug 1. Clean and wipe dry the tube end to be plugged. 2. For an EX-3 plug, insert plug into tube until large washer is flush against tubesheet. For an EX-4 plug, insert plug into tube beyond flush of tubesheet. 3. For EX-3 plug, hand-tighten nut finger tight, using open end or box wrench, turn nut 2-3 complete revolutions. For EX-4 plug, hand-tighten finger tight, using deep well socket wrench, turn nut 2-3 complete revolutions. 4. The end of the bolt is slotted. Use a screwdriver to hold the bolt in place while tightening the nut with a 7/16 in. (11 mm) box wrench. Tighten to desired torque.

Figure C-5 Conco EX-F Expanding Tube Plug

C-4

EPRI Licensed Material Tube Plugging Procedures Table C-5 Installation Procedures for the Conco EX-F Expanding Tube Plug 1. Clean and wipe dry the tube end to be plugged. 2. Insert plug into tube beyond flush of tubesheet. 3. Hand-tighten finger tight, then using deep well socket wrench, turn nut 2-3 complete revolutions. 4. The end of the bolt is slotted. Use a screwdriver to hold the bolt in place while tightening the nut with a 7/16 in. (11 mm) box wrench. Tighten to desired torque.

Figure C-6 Conco FP Fiber Tube Plug Table C-6 Installation Procedures for the Conco Fiber Tube Plug 1. Clean and wipe dry the tube end to be plugged. 2. Using hammer, lightly pound plug into tube.

Figure C-7 Conco Pin Plug

C-5

EPRI Licensed Material Tube Plugging Procedures Table C-7 Installation Procedures for the Conco Pin Plug 1. Clean and wipe dry the tube end to be plugged. 2. Using hammer, lightly pound plug into tube or tubesheet. 3. Can be welded into position if necessary.

Figure C-8 Conco Pin and Collar Tube Plug Table C-8 Installation Procedures for the Conco Pin and Collar Tube Plug 1. Clean and wipe dry the tube end or tubesheet hole to be plugged. 2. Use hammer to lightly seat collar into tube or tubesheet. 3. Use hammer to lightly pound pin into collar. 4. Can be welded into position if necessary.

C-6


Expansion Seal Technologies VibraProof, Perma, and Expandable Thimble Plug

Figure C-9 Expansion Seal Technologies VibraProof Condenser Plug

C-7

EPRI Licensed Material Tube Plugging Procedures Table C-9 Installation Procedures for Expansion Seal Technologies VibraProof Condenser Plug 1. Clean and dry the tube end or tubesheet hole to be plugged. Remove any loose scale, deposits, and foreign materials. 2. Select and insert the proper size VibraProof plug and tighten the compression nut with a torque wrench. Tighten to 2.5 Ft-lbs. (3.4 N-m) for 0.500 in. to 0.869 in. (13 to 22 mm) ID tube or tube holes; or 9 Ft-lbs. (12.2 N-m) for 0.870 in. to 1.309 in. (22 to 33 mm) ID tubes or tube holes. 3. Tighten lock nut against compression nut. 4. As with any elastomer plug, a program of periodic inspection, every one to two years, should be established and followed.

Figure C-10 Expansion Seal Technologies Condenser Perma Plug

C-8

EPRI Licensed Material Tube Plugging Procedures Table C-10 Installation Procedures for Expansion Seal Technologies Condenser Perma Plug 1. Determine the ID of the tube or tubesheet hole using EST’s simple Go / No-Go Gage. 2. Match the Go / No-Go Gage size with a dedicated Tube Cleaning Brush and prepare the tube end/tube hole by brushing with EST’s Tube Cleaning Brushes. A properly sized brush will be a tight interference fit with the tube end. Brushing should be performed using a battery or air-operated drill. Brush with a smooth in and out motion for an interval of 5 seconds in brass, bronze, 90/10 copper nickel and soft alloy tubes, or 30 second intervals for steel, stainless steel, 70/30 copper nickel, titanium, and hard alloys. (Brushing removes tube wall pitting and the effects of erosion and corrosion. It reduces tube ovality and sizes the tube; and it provides an ideal sealing surface for the Perma Plug.) Stop brushing after each interval and visually inspect the tube. If brushing has accomplished its objectives, continue to the next step. If not, brush for another interval and reinspect. If the brush feels loose in the tube it might be necessary to move up to the next larger brush size and continue brushing. Brushing can be facilitated by periodically dipping the Tube Cleaning Brush in Brush Lube. Re-gage the tube end with the Go / No-Go gage to confirm the correct plug size. 3. Insert the Pull Rod Assembly into the Ram and recess the plug within the tube end or tubesheet hole so that the installed plug will be flush with or slightly recessed from the tubesheet face. Always install the plug within the region of the tubesheet. 4. Operate the ram until the integral breakaway pops and the plug is set. Remove the remaining breakaway piece from the end of the conical pin. Note: field experience has shown that total installation time for Perma Plugs from initial preparation through plug installation is generally 2-4 minutes per tube end.

Figure C-11 Expansion Seal Technologies Expandable Thimble Plug

C-9

EPRI Licensed Material Tube Plugging Procedures Table C-11 Installation Procedures for Expansion Seal Technologies Expandable Thimble Plug 1. Using an internal tube cutter, cut the tube just beyond the tubesheet and remove the stub end from the tubesheet hole. 2. Brush the tubesheet hole using a properly sized tube cleaning brush. Brushing will remove any scoring or damage caused by the tube removal process. 3. Select the proper size and material of expandable thimble plug and insert it into the tubesheet hole. The tapered nose of the thimble should slip into the exposed end of the original tube. 4. Roller or hydraulically expand the thimble into the tubesheet. 5. Using an internal tube cutter or facing tool, remove any projection of the thimble past the tubesheet face. 6. (Optional) Carefully drive a fiber hammer-in taper plug to the open end of the installed thimble to identify that the tube end has been plugged.

Heat Exchanger Products Inc. (HEPCO) Brass Condenser Tube Plug

Figure C-12 HEPCO Brass Condenser Tube Plug Table C-12 Installation Procedures for the HEPCO Brass Condenser Tube Plugs 1. Make sure the tube is free of excess debris at the opening. Wipe with cloth if needed. 2. Insert tube plug all the way into the tube until the collar comes to rest on the tubesheet. 3. Holding the collar in place, use HEPCO pre-set torque wrench or torque to 33 inch-lbs. (3.7 N-m) and torque down hex head nut.

C-10


Torq N’ Seal™ Condenser Plug and High Pressure Tube Plug

Figure C-13 Torq N’ Seal¥ Condenser Tube Plug Table C-13 Installation Procedures for the Torq N’ SealTM Condenser Tube Plug 1. The Torq’N Seal¥ Condenser Plug should NOT fit into the condenser tube until the expansion screw is used to reduce the plug diameter. 2. Remove the end cap by turning to the right. Insert a slotted screwdriver into the expansion screw and turn to the left. That will reduce the diameter until the plug fits into the tube inside diameter. 3. Be sure to wipe the tube inside diameter with a clean cloth so that it is dry before installation of the plug to ensure a good friction fit.

4. Insert the Torq'N Seal¥ Condenser Plug into the tube with the flange pressing against the tubesheet. Tighten the expansion screw to the right until the plug is seated as tight as possible without stripping the slotted head. Replace the protection end cap onto the expansion screw by turning to the left. See Figure C-13.

Figure C-14 Torq N’ Seal¥ High Pressure Tube Plug

C-11

EPRI Licensed Material Tube Plugging Procedures Table C-14 Installation Procedures for the Torq N’ Seal¥ High Pressure Tube Plug 1. A careful measurement of the tube inside diameter should be taken with an inside tube micrometer or a gauging block to determine the actual bore diameter. Select a Torq N’ Seal¥ plug that is sized within the range of the measured tube inside diameter: for a 0.518 in. (13 mm) inside diameter tube, use a TNS/0.510 – 0.530 inch (13.0 – 13.5 mm). 2. Clean tube of any loose scale or corrosive oxide formation. If the tube is out of round, extremely eccentric or cracked, a straight spiral drill reamer should be used to resize the bore of the tube or remove the tube completely. 3. After the correct size plug is chosen, a ratcheting torque wrench should be used to install the plug. Insert the plug into the tubesheet area of the heat exchanger. Use of Screw Grab will hold the Torq N’ Seal¥ plug onto the Torx¥ or hex bit driver. 4. Insert the plug into the tubesheet area of the heat exchanger and begin slowly tightening to the right until you feel the eccentric cam lock in place. If the cam does not lock, then the plug is too small for that particular application. After the cam locks, the applied torque will feel as if there is an even resistance (approximately 150 in. lb.) (17 N-m) as the plug body expands. When the torque necessary to tighten the plug increases, use an accurately calibrated torque wrench to achieve the final torque value as follows: Plug Material Plug Size - in. (mm) Torque - In. lbs. Drive Size (N-m) Carbon Steel 0.430 – 0.560 400 (45.2) Torx T45 (11 – 14) 0.570 – 0.710 450 (50.8) Torx T50 (14.5 – 18.0) 0.730 – 0.980 500 (56.5) 3/8 in. Hex (18.5 – 25) (9.5 mm) Brass 0.430 – 0.560 250 (28.2) Torx T45 (11 – 14) 0.570 – 0.710 300 (33.9) Torx T50 (14.5 – 18.0)

Cupra Nickel

Stainless Steel

C-12

0.730 – 0.980 (18.5 – 25) 0.430 – 0.560 (11 – 14) 0.570 – 0.710 (14.5 – 18.0) 0.730 – 0.980 (18.5 – 25) 0.430 – 0.560 (11 – 14) 0.570 – 0.710 (14.5 – 18.0) 0.730 – 0.980 (18.5 – 25)

350 (39.5) 250 (28.2) 300 (33.9) 350 (39.5) 500 (56.5) 550 (62.1) 600 (67.8)

3/8 in. Hex (9.5 mm) 1/4 in. Hex (6 mm) 5/16 in. Hex (8 mm) 3/8 in. Hex (9.5 mm) 1/4 in. Hex (6 mm) 5/16 in. Hex (8 mm) 3/8 in. Hex (9.5 mm)


D POP-OUT SUMMARY

The following list provides the location of key Pop-Out information in this report. Key Human Performance Point

Section

Page

Key Point

4.3

4-5

There are two principal ways of estimating a condenser’s current performance, the Heat Exchange Institute (HEI) method [6] and the ASME method [7]. Both compare the current value of the effective heat transfer coefficient (Ueff), computed from present steam and water temperatures and cooling water flow rate, with a reference value calculated according to one of the two procedures.

4.5

4-9

The ASME reference value of the heat transfer coefficient is a single-tube value and the HEI reference value is an overall tube bundle heat transfer coefficient. The value of the effective cleanliness factor (HEI method) is greater than the corresponding performance factor (ASME method) on the same condenser. It has also been observed that the design value of the ASME performance factor and the HEI cleanliness factor varies with load.

5.4.2

5-20

To be effective in controlling biofilm formation all biocides require adequate dosage, contact time with the biomass, and frequent application.

5.4.2.2

5-21

The biocide label lists restrictions that govern the use of the biocide for all applications. It also lists danger signs, environmental hazards, treatment methods, storage and disposal instructions, and how to apply initial and subsequent dosages.

5.4.3

5-23

The Environmental Protection Agency (EPA) and the states mandate three types of regulations governing the quality of discharges. They are technology-based regulations, historically based effluent water quality standards, and receiving water quality-based standards.

5.4.3.1

5-25

In general, the technology-based regulations are species or compound-specific numerical limits, either concentration or mass per unit time. These limitations are based on the performance of the best available technology on the particular category of effluent for a particular industry. These limitations are typically the least restrictive limits that can be imposed.

5.4.4

5-26

Oxidizing biocides are usually the primary biocontrol agents for once-through and recirculating condenser cooling water systems. Non-oxidizing biocides seldom are used in once-through condenser cooling water systems except for special applications such as macrofouling control.

D-1

EPRI Licensed Material Pop-Out Summary Section

Page

Key Point

5.4.4.1

5-27

Chlorine gas is very toxic and extremely irritating. It is a green vapor that is denser than air. Small leaks can be detected with a 10% solution of ammonia hydroxide. The chlorine and ammonia vapors form a white vapor of ammonium chloride.

5.4.4.1

5-28

Appropriate safety equipment such as chlorine gas masks should be available in case a leak occurs in feedlines or at cylinder connections. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions.

5.4.4.1

5-29

Appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment used to store or feed sodium hypochlorite. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions.

5.4.4.1

5-30

Dry chlorine release chemicals are similar to dry bromine release chemicals. Appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment used to store or feed chlorine. A dust mask can also be used. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions.

5.4.4.2

5-32

Appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment storing or feeding bromine compounds. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions.

5.4.4.3

5-36

For non-oxidizing biocides, appropriate safety equipment such as facemask, eye goggles, rubber gloves, and apron should be worn when handling any equipment used to store or feed the chemicals. Some of the non-oxidizing biocides are extremely irritating. They can penetrate clothing, shoes, or leather and are rapidly absorbed through the skin. Some emit toxic irritating vapors. Great care should be taken in handling all non-oxidizing biocides. Consult the Material Safety Data Sheet and product label for specific safety handling and spill precautions.

5.4.4.3

5-36

Biocides are regulated by the EPA. Each biocide must be registered for a specific use such as microbiological control. In addition, it must be registered for the specific cooling water systems in which it can be used. The container label must specify a variety of information, including at a minimum, the percent of each active component, product use instructions, safety handling precautions, EPA registration number, and the EPA manufacturing location number.

6.1.1

6-7

Ball replacement is a normal operating cost associated with proper system operation. The manufacturers normally recommend replacing a complete charge of balls approximately once a month because of ball wear. Historical operating data show that ball usage is often much higher. New designs might be an improvement in ball life.

6.2.5

6-21

When high-pressure water lancing equipment must be used, it presents a potential safety hazard to operating personnel because of pressures as high as 8000-10,000 psi (55-69 megapascals). Often this equipment is used by a contractor who specializes in high-pressure equipment. Propelling the cleaning devices through the tubes with high-pressure air or air/water also presents a safety hazard due to very high travel speeds.

7.2.1.4

7-15

The unit air in-leakage survey should start on the turbine deck at one end of the unit, continue around the turbines, include any other components on the deck applicable to the test, and then proceed in a similar manner with the next deck

D-2


Page

Key Point down. Regardless of the type of gas used for testing, the test should be performed from the top of the unit to the bottom of the unit, one floor at a time. By performing the test first on the upper elevations, the tracer gas drifting to unknown leak locations is reduced.

7.4.1

7-26

Most plants use continuous monitoring of cation conductivity in the condensate, feedwater, and/or steam generator blowdown as the primary indication of the presence of condenser in-leakage.

7.4.2

7-29

Water chemistry guidelines for PWR once-through and recirculating steam generators can be found in EPRI TR-102134-R5, PWR Secondary Water Chemistry Guidelines, May 2000.

7.4.3

7-30

Water chemistry guidelines for BWR units can be found in EPRI TR-103515-R2, BWR Water Chemistry Guidelines, February 2000.

7.5

7-30

Even when the leaking tube has been positively identified, insurance plugging can be considered good maintenance practice. In many cases, the exact mechanism that caused the tube to fail is uncertain. Selecting surrounding tubes to be plugged is insurance against additional leaks developing before the next outage. Those tubes with insurance plugs can then be subjected to eddy current testing during the next outage so that as many tubes as possible can be returned to service.

7.5

7-31

Once the leaking bundle has been identified, a number of methods are available to determine exactly which tubes or joints are leaking. All of the methods commonly used involve testing areas of the tubesheet sequentially until the area of the leak(s) is evident. Testing then progresses to smaller areas until the exact leak location is found. The most commonly utilized leak location methods are tracer gas, plastic film, soap film NDE, smoke, water fill, rubber stoppers, pressure vacuum, and hydrostatic testing.

7.5.10

7-34

EPRI has developed and patented a system that uses targeted injection of sulfur hexafluoride (SF6) to detect and locate condenser tube leaks while the condenser is in full operation. The system is called the Condenser On-Line Leak Detection System (COLDS) and a description of it is found in EPRI document AP101840-V3P2, published in December 1995. It can locate leaks with flow rates as low as 1 gallon (4 liters) of water per day and small leaks that cannot be located with off-line techniques.

8.1.1

8-2

INPO determined that the following are causes of the personnel injuries from Hydrolaser use: x

Improper work practices

x

Inappropriate personal protection equipment

x

Failure to implement operating experience

8.3.3

8-27

Lay-up refers to all measures taken to prevent significant condenser corrosion during outages. Exposure of condenser parts to stagnant water during lay-up can lead to accelerated, localized corrosion.

9.4.4.1

9-18

Where the bidding process might result in a different contractor being employed for each inspection, the necessity for a common procedure ensures that eddy current data from one inspection can be compared with confidence to the data from inspections conducted in earlier years. Without such formal procedures and owner supervision, reliable data trending is virtually impossible.

D-3


Page

Key Point

9.4.4.6

9-19

The term figures of merit as used in the analysis of eddy current tests is the generic name applied to various criteria used to compare test results. Figures of merit have different criteria in the case of a condenser compared with those for a heat exchanger. With heat exchangers, considerations of meeting the Pressure Vessel Code override questions of mere wall penetration. In any given plant, there should be some agreement on how corrosion figures of merit will be defined when evaluating eddy current test results.

10.5

10-22

Tubes in service have defects. These defects or indentations can result from installation or in-service conditions. The liner might not be able to overcome all tube inside diameter defects and, thus, will not be expanded to meet the tube inside diameter by hydro-expansion. The defects create air pockets that can significantly retard heat transfer. Because of the uncertainty of the application results, it is recommended that heat transfer studies be conducted on several samples of the tubes to be lined. In this way, the effect on heat transfer can be established prior to the relining process being implemented in the field.

10.6

10-22

The full-length tube coating material is applied with an average thickness of 2–4 mils (51–102 µm). However, the actual coating thickness selected has to be balanced between solving a particular problem and retaining sufficient tube heat transfer capability.

11.5.1.4

11-25

Recent improvements in technology have resulted in tooling that can pull an entire tube and chop the tube into pieces in a single operation at the tubesheet. This improvement is significant because it reduces both the labor and space required for tube removal.

11.5.1.8

11-28

Sufficient labor should be planned for tube insertion. Good practice is to provide one worker for each 10 feet (3 meters) of tube to be inserted.

D-4

EPRI Licensed Material Pop-Out Summary

Key O&M Cost Point

Section

Page

Key Point

2.4.2

2-9

Two pass condensers are selected when the cooling water is a premium quantity, installation space is restricted, or the plant layout dictates that the inlet and outlet must be at the same end of the condenser. In plants with cooling towers, a two pass condenser can reduce the size and, therefore, the cost of the cooling tower.

2.4.9

2-13

Generally, multi-compartment condensers lower average backpressure in the lowpressure turbine without a significant decrease in the temperature of the condensate leaving the hotwell. The lower condenser backpressure means increased turbine efficiency.

4

4-1

Condenser performance significantly affects the heat rate and generation capacity of a power plant. A 1 in. Hg (2.5 cm Hg) increase in turbine backpressure can result in a 2% increase in heat rate.

4.1.1

4-3

As a rule of thumb, each 5 degrees of condensate subcooling results in a 0.5% increase in heat rate.

5.2.6

5-13

Gaseous chlorine is frequently used by utilities because chlorine in this form is relatively low in cost. Unfortunately, chlorine gas is highly toxic. Sodium hypochlorite, although less dangerous, is more expensive than liquid chlorine.

5.4.4.3

5-35

Most non-oxidizing biocide applications are much more expensive than oxidizing biocides, but site-specific conditions could change this. Generally, non-oxidizing biocides are applied once per week or several times per month, as compared to several times daily for the oxidants.

10.1.2

10-3

In situations where previously installed plugs are missing, leaking, or have caused collateral damage to the tube and tubesheet, the actual plug cost should not be a major factor. The expense associated with controlling persistent water in-leakage as a result of tube and plug leaks can be many times the cost of even the most expensive plug.

D-5

EPRI Licensed Material Pop-Out Summary

Key Technical Point

Section

Page

Key Point

2.5.1

2-14

The condenser shell is designed to withstand up to 15 psig (1 kg/cm²) and, therefore, is not governed by the ASME Pressure Vessel Code. The only design code applicable to condensers in the utility industry is the Heat Exchange Institute (HEI) standards.

2.5.5

2-15

In the air-removal section of the tube bundle, the tubes are exposed to an oxygenated, ammonia-rich environment. This environment promotes condensate corrosion (grooving) in copper-alloy tube materials. For this reason, the tube materials in this section are made from a more corrosion-resistant alloy such as stainless steel.

3.1

3-2

Backpressures lower than design tend to improve heat rate. Therefore, lower backpressures are desirable. However, the backpressure should not be so low that it is the cause of unnecessary condensate subcooling (see the discussion in Section 4.1.1).

3.3.2

3-7

A gradual decrease in vacuum by the steam jet air ejectors could be caused by a corroded or eroded nozzle, condensate trap mis-operation, clogged loop seal drain pipe, leaking cooler tubes, and wet steam.

4.7

4-10

The following parameters should be measured when monitoring condenser performance: inlet and outlet tube side pressure, inlet and outlet cooling water temperature, impressed cathodic protection settings, condenser cleanliness factor, sample fluids for contamination, turbine backpressure, and air in-leakage levels.

5

5-1

There are two main types of biofouling: macrofouling and microfouling. Macrofouling is defined as the blockage of condenser tubes by organic or inorganic debris such as sticks, leaves, fish, mussels, and so on. Microfouling is the accumulation of deposits (inorganic scales or organic growths) on the inside of the tubes.

5.2

5-4

A variety of macrofouling control technologies are used in power plants. These technologies can be categorized as: mechanical control, flow reversal, thermal backwash, hydraulic control, materials control, chlorination and alternate biofouling control methods, and manual cleaning.

5.2.3

5-11

Thermal backwash is an antifouling technique that requires the cooling water temperature to be raised above the thermal tolerance level of the fouling organism, for example, zebra mussels.

5.2.4

5-12

The use of high circulating water velocity to prevent the attachment and subsequent growth of fouling mechanisms is termed hydraulic control. The velocity needed to prevent settlement of the fouling organisms is between 2 and 4 ft/sec (37 and 73 meter/min) on smooth surfaces and 4 to 6 ft/sec (73 to 110 meter/min) on rough surfaces.

5.2.5

5-13

Copper-nickel alloys form an adherent cuprous oxide corrosion film. The copper ion content in the film, when released into the cooling water, is toxic to marine biofouling organisms and inhibits their attachment to the metal surface.

5.3.1.2

5-17

Several factors are involved in the accumulation and development of the biofilm

D-6


Page

Key Point including surface conditions, water quality, fluid velocity, water temperature, and tube alloy.

5.3.2

5-19

Chemical additives used for biological control or corrosion inhibition can also result in microfouling. For example, water that contains manganese will react with chlorine to form manganese dioxide particles and substantially increase fouling risk. Copper alloys and 300 series stainless steels are likely to suffer significant corrosion under these circumstances.

5.4

5-19

Several factors must be considered when using chemicals to control microfouling of main steam condenser cooling water systems. These factors include condenser cooling system design and operation, biocontrol agents, environmental regulations, chemical application methods, and safety and exposure.

6

6-1

Some performance parameters that indicate condenser cleaning is needed are increased condenser backpressure, decreasing cleanliness factor, decrease in inlet and outlet cooling water temperature difference, heat rate increase, and megawatt output decrease.

6

6-2

The on-line cleaning techniques include the sponge ball system, brush and cage system, abrasive cleaning, and self-aligning rockets. These systems can require a large capital investment. A continuous cleaning system offers the advantage of keeping the tubes clean without any fouling buildup. Some additional maintenance and operations attention is required. The constant scraping of the tube inside walls can cause tube thinning.

6

6-3

The off-line cleaning techniques include the use of brushes, scrapers, and hydroblasting. The equipment costs for these systems are relatively inexpensive. The unit must be derated or off-line in order to clean the tubes. Tube cleaning can be scheduled during refueling/boiler outages or during a scheduled load reduction. The cleaning process requires an operator and the air and water pressures used can impose a safety concern.

6.3

6-22

Typically, on-line and off-line chemical cleaning techniques remove 3-10 mils (76 –254 µm) of deposit in 30 to 60 hours. On-line techniques are applied to one waterbox at a time or to the entire condenser. The off-line techniques apply to the entire condenser. Chemical cleaning of the condenser typically regains lost megawatts.

7.4

7-26

Prevention of cooling water in-leakage is important in all cooling water systems. It becomes critical when brackish water or seawater is used for cooling. A leakage on the order of 0.1 gallons per minute (gpm) (23 liters/hr) might be unacceptable and can cause significant corrosion.

8.2.3

8-13

Dezincification of Muntz metal is the most commonly reported dealloying problem in condensers. In the absence of other corrosion accelerating factors, Muntz metal tubesheets are normally thick enough (nominally 1 to 1.5 inches (2.5 to 3.8 cm)) to withstand the dezincification that occurs. However, in cases where galvanic-induced corrosion is significant, such as a Muntz metal tubesheet fitted with titanium tubes, dezincification has occurred at penetration rates exceeding 0.5 inches (1.3 cm) per year.

8.2.5

8-16

The primary factors affecting the magnitude of current flow and rate of galvanic corrosion are the potential differences between the metals, the environmental aspects of the electrolyte, the polarization behavior of the respective metals, and the relative areas of the coupled metal. The environmental factors having the greatest effect on the galvanic corrosion rate are cooling water conductivity and

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Key Point temperature.

8.2.8

8-18

Random pitting along the length of a condenser tube is the most commonly encountered condenser corrosion problem. Pitting is manifested most frequently in copper tubes but stainless steel is also susceptible.

8.2.9

8-19

Steam side erosion occurs as a result of wet steam or entrained water droplets traveling at a high speed and impacting on the surface of the tubes. The severity of impingement attack is a function of the kinetic energy of the fluid, the impact velocity, the mass flow per unit area, the hardness of the tube material, and the exposure time.

8.2.11

8-20

Flow-induced vibration damage occurs in condensers because the spacing between supports is too large or because the baffling at high-energy inlet connections does not provide adequate dispersion of the flow jet at the connection.

9.3.1

9-4

Cleaning by mechanical and/or chemical techniques is the only preventive task that prevents corrosion or slows its progression, maintains tube reliability, and extends the life of the tubes.

9.4.4

9-15

ET is a non-destructive test technique that causes electrical currents to be induced in the material being tested. The associated magnetic flux distribution within the material is then observed. Because the results from eddy current testing can be affected by a number of factors, successful eddy current testing requires a high level of operator training and awareness.

9.4.4

9-16

Eddy current instruments and recording instruments have a limited frequency response, that is, they require a certain time to respond to an input signal. Therefore, pulling an ET probe through a tube at a high speed will result in poor examination. Most testing should be performed at probe speeds of 60 to 120 feet per minute (18.3 to 36.6 meters/minute).

9.4.4

9-16

It is recommended that the tubes be cleaned before performing ET. By bringing the tubes to a clean state, the possible effects on the electromagnetic flux distribution of any deposits present will be minimized.

9.4.4.8

9-20

Depending on the degradation factor, the allowable wall loss can be in the range of 50-90 percent wall loss. Consequently, if the eddy current sizing error of 10 percent is used, the resultant plugging criteria can be 40-80 percent wall loss.

10.2

10-18

Metallic shields restore tube-to-tubesheet joint strength, extend bundle life, have no negative effect on heat transfer, and reduce the tube opening by a fraction of that associated with plastic tube inserts.

10.2

10-18

Corrosion-resistant insert materials typically specified are: AL-6X, AL-6XN, 7030, 85-15 or 90-10 Cu-Ni and 304 or 316 Stainless Steel. AL-6X is the most widely used insert material.

10.4

10-20

An alternative approach to tube inserts for tube end erosion/corrosion problems is to apply a tube end epoxy coating that can halt the erosion process. The coatings are applied in multiple coats for a total coating thickness of 9 to 10 mils (229 to 254 µm). The coatings are applied to the required depth into the tube end, with the depth usually being between 2 and 30 inches (5 and 76 cm), depending on the width of the waterbox. The metallurgy of the tube to be coated is not significant because the coating is compatible with all tube materials.

10.8

10-25

Manufacturers recommend that epoxy coatings not be subjected to high temperatures (> 170°F (76.6°C)) or allowed to freeze. If tubes mounted in

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Key Point tubesheets that have had the cladding applied, subsequently leak, they should not be plugged with tapered brass or fiber plugs. Expandable plugs are preferred because they do not put pressure on the coating. Plugs should never be hammered into tubes in tubesheets after they have been coated.

10.10

10-29

The material selection for coating waterboxes depends on whether the waterboxes are new or have been in-service, coated in a manufacturer’s shop, or coated inside the plant. When coating new waterboxes, epoxies, rubber lining, or solvent-filled epoxies (coal tars) are used. Waterboxes coated inside the plant use epoxy coatings for performance, longevity, and personnel safety considerations.

11

11-1

The current industry experience has been to replace copper-bearing alloys with high alloy, pit-resistant steels and titanium. These materials are significantly lighter in weight and higher in yield strength, but they have lower thermal conductivities than the copper-bearing alloys.

11

11-2

Another consequence of retubing with one of the newer materials is the likely need for additional tube support plates or tube staking to reduce the tendency of the tubes to vibrate.

11.3.4

11-19

The primary advantage of an expanded and welded joint is that it can provide greater axial strength and better leak integrity than an expanded joint for titanium and stainless steel tubes with tubesheets of weld-compatible materials.

11.5.2

11-29

In a rebundling approach, the tube spacing can be reduced with an increase in the number of tubes. This increase in tube side flow area generally results in reduced condenser circulating water pressure drop and an increase in circulating water discharge from the existing circulating water pumps. The resulting total circulating water flow to the rebundled condenser is higher. Generation might be increased with a more efficient design.

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Plant Maintenance Support

Equipment Reliability

Condenser Maintenance and Operation

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