condenser maintenance and operation

Condenser Application andMaintenance Guide

Technical Report

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Equipment

Reliability

Plant

Maintenance

SupportReduced

Cost

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Condenser A

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EPRI Project ManagerA. Grunsky



1003088

Final Report, August 2001

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CITATIONS

This report was prepared by

Nuclear Maintenance Applications Center (NMAC)EPRI1300 W.T. Harris BoulevardCharlotte, 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 informationon the operation, maintenance, and performance of condensers. The contents of this guide willassist the plant in improving condenser performance, reducing maintenance costs, and inincreasing condenser reliability.

BackgroundAs the age of a condenser increases, the maintenance costs required for continued operation ofthe condenser also increase. Unit reliability and lost energy costs are affected by condenserperformance.

Objectivesx To provide station personnel with reliability, performance, and maintenance practices for the

condenser.

x To provide a comprehensive guide for condenser equipment.

ApproachThis guide is structured to provide a comprehensive overview of condenser equipment. Anextensive search of previously written EPRI guidelines was conducted to provide relevantinformation 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, troubleshootingoperational problems, performance calculations and instrumentation, macrofouling andmicrofouling control techniques, mechanical and chemical cleaning, air and water in-leakagedetection and correction methods, industry failure data, mechanisms and corrosion preventionpractices, preventive maintenance tasks, non-destructive examination testing and results, tubeplugs, inserts, sleeves, coatings, liners, staking, waterbox and tubesheet repairs, remaining lifeassessment, component materials, constructability issues, retubing, rebundling, and the results ofan industry survey.

The guide includes the following sections:

x Introduction

x Tutorial

x Troubleshooting

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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. Unitreliability and lost energy costs are affected by condenser performance. This guide provides acomprehensive overview of the equipment practices needed for continued reliable operation.

KeywordsCondenserPerformanceMaintenanceReliabilityFoulingCleaning

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ABSTRACT

The condenser is a critical component in a nuclear power plant. As the age of a condenserincreases, the maintenance costs required for continued operation also increase. Fouling affectscondenser performance and cleaning is required to restore performance. Troubleshootingproblems with high condenser pressure is a common occurrence. Condition-based maintenance isimportant for long-term reliability of this equipment.

Tube leaks are the primary cause of lost production caused by the condenser. Maintenancerepairs include installing tube plugs, inserts, sleeves, shields, coatings, liners, tube bundle stakes,and waterbox and tubesheet repairs. Retubing might be needed to restore performance. Thisguide is a comprehensive treatment of all aspects of condenser maintenance and is to be used byplant maintenance engineers to improve condenser performance and reduce maintenance costs.

EPRI Licensed Material

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ACKNOWLEDGMENTS

The Condenser Application and Maintenance Guide was produced by the Nuclear MaintenanceApplications Center (NMAC) and the following members of the Condenser Guide TechnicalAdvisory Group (TAG). NMAC would like to thank the following individuals for theirparticipation in the preparation and review of this report.

Technical Advisory Group Members:

Name Utility

Tim Eckert EPRI Plant Support Engineering

Chuck George Carolina Power & Light

John Harvey Entergy Operations, Inc.

Bob Littlejohn Tennessee Valley Authority

Dennis Mason Duke Power Company

Eric May Dominion Nuclear Services

Mark Meltzer Public Service Electric & Gas

Eric Steckhan Exelon Corporation

Name VendorBob Boberg Framatome Technology

Chris Johnson Heat Exchanger Institute

Jim Mitchell Plastocor, Inc.

George E. Saxon, Jr. Conco Systems, Inc.

Fritz Sutor Expansion Seal Technologies

NMAC and the Technical Advisory Group were supported in their efforts to develop this guideby:

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 DesignCondenser ..................................................................................................................... 2-9

2.4.4 Two-Compartment, Single-Pass, Transverse Flow, Series DesignCondensers ................................................................................................................... 2-9

2.4.5 Two-Compartment, Single-Pass, Axial Flow Condenser..................................... 2-10

2.4.6 Three-Compartment, Single-Pass, Transverse Flow, Parallel DesignCondenser ................................................................................................................... 2-11

2.4.7 Three-Compartment, Single-Pass, Transverse Flow, Series DesignCondenser ................................................................................................................... 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


xix

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


xxi

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 DesignCondenser..................................................................................................................... 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


xxii

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 PlanarViews ............................................................................................................................ 8-18

Figure 8-6 Stress Corrosion Cracking of Admiralty Brass, Magnified Cross-Section andPlanar 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 PerforatedBaffle 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


xxiii

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


xxv

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 ProtectionApplications................................................................................................................... 8-24

Table 8-11 Salt/Brackish Water Condenser Materials and Galvanic CorrosionProtection 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


xxvi

Table 11-7 Tubesheet Hole Size Limits.............................................................................. 11-27

Table C-1 Installation Procedures for the Atlantic Group Brass and Fiber Jacketed TubePlug.................................................................................................................................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 VibraProofCondenser Plug...............................................................................................................C-7

Table C-10 Installation Procedures for Expansion Seal Technologies Condenser PermaPlug.................................................................................................................................C-9

Table C-11 Installation Procedures for Expansion Seal Technologies ExpandableThimble 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


1-1

1 INTRODUCTION

1.1 Background

With the age of steam condensers approaching twenty-five years for nuclear plants and fortyyears for fossil units, the cost of operating and maintaining this equipment is increasing. Thefrequency of testing, cleaning, repairs, and re-tubing efforts is increasing because of the age andcondition of the equipment. In addition, there are performance losses associated with biofoulingand air/water in-leakage. Long-term reliability of the condensers is important to maintain loadand performance in power plants.

In 1999, EPRI NMAC (Nuclear Maintenance Application Center) sent a survey to their membernuclear plants requesting input on equipment that might need NMAC attention. Issues withcondensers were characterized by the words, “air in-leakage, baffles, and tube integrity.” Theresponses were about even as to whether or not the condenser equipment needed furtherattention. The topic of condensers was again discussed at the August 2000 meeting of the NMACSite 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 thedevelopment 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.


Introduction

1-2

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 andvendors for input. A technical advisory group (TAG), composed of seven nuclear utilityrepresentatives, four vendors, one EPRI Plant Support Engineering Project Manager and onemember from the Heat Exchanger Institute (HEI), provided input and a detailed review of theguide.

This guide updates the NMAC ABCs of Condenser Technology guide and incorporates thatinformation 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 becauseair 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 waterpump, 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 thisguide apply to both types of plants.

A survey was sent to the EPRI member condenser contacts in the nuclear and fossil plants. Thesurvey requested information on the design, materials, cleaning practices, chemical watertreatment, cathodic protection, etc. of each plant. The intent of the survey was to provide aninformation source for plant personnel with similarly designed plants and similaroperation/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 Pop-Outs.

2. The Tutorial section includes descriptions for Operation, Rankine Cycle, SecondaryFunctions, 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 TransferCoefficient, HEI Method, ASME Method, Turbine Blade Effects, Performance Monitoring,Performance Software Tools, and Instrumentation.


Introduction

1-3

5. The Fouling section includes Macrofouling, Macrofouling Control Technologies,Microfouling, Microfouling Chemical Treatment, Fouling Monitor, and TargetedChlorination with Fixed Nozzles.

6. The Cleaning section includes Mechanical On-Line Cleaning Systems, Mechanical Off-LineCleaning Systems, and Chemical Cleaning.

7. The Air/Water In-Leakage section includes Air In-Leakage Effects, Air In-LeakageDetection Methods, Correcting Air In-Leakage, Water In-Leakage Effects, Water In-LeakageDetection Methods, and Correcting Water In-Leakage.

8. The Failure Modes section includes Failure Data, Failure Mechanisms, and GeneralCorrosion 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, TubeEnd Coatings, Full Length Tube Liners, Full length Tube Coatings, Re-Expanding the Tube-to-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 LifeAssessment, Tube Material Selection, Tubesheet Joints and Material Selection, Waterboxand 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 MechanicalTube 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 decidedthat a reference system would be used for the appropriate sections. Reference numbers inbrackets, [#], are used at the beginning of certain sections and after the titles on tables andfigures to denote the source of the majority of information in that section. The reference numbersand 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 letteredboxes, which succinctly re-state information covered in detail in the surrounding text, making thekey point easier to locate.


Introduction

1-4

The primary intent of a pop-out is to emphasize information that will allow individuals to act forthe benefit of their plant. Utility and EPRI personnel who reviewed and prepared this guideselected the information included in these pop-outs.

The pop-outs are organized according to three categories: O&M Costs, Technical, and HumanPerformance. Each category has an identifying icon to draw attention to it when quicklyreviewing the guide. The pop-outs are shown as follows:

Key O&M Cost Point

Emphasizes information that will result in overall reduced costs and/orincrease 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 inorder to prevent personal injury, equipment damage and/or improve theefficiency 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 thereport. By reviewing this listing, users of this guide can determine if they have taken advantageof key information that the writers of this guide believe would benefit their plants.


2-1

2 TUTORIAL

2.1 Condenser Operation

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

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


Tutorial

2-2

An open circulating water system consists of fresh, brackish or saltwater pumped into thecondenser from a river, lake, or ocean and returned to the same body of water. The circulatingwater might pass through trash rakes, a trash rack, and traveling screens before being pumped bythe circulating water pumps into the condenser. This heated circulating water is then returned tothe river, lake, or ocean downstream of the inlet to the condenser. Federal and stateenvironmental restrictions apply to the temperature and composition of the water returned to theriver, lake, or ocean. The flow path is known as an open circulating, cooling water system thatwill 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 circulatingwater is supplied to the condenser through pumps or is gravity fed. The circulating water goesthrough the condenser and is returned to the pond or cooling tower. Heat from the circulatingwater is released to the atmosphere and surrounding water. The water is then returned to thecondenser to start the cycle again. Makeup water is provided for any evaporation or leakagelosses.

Within the condenser shell are several components that use the condenser as a place to releaseheat. Various steam vents and drains are piped to the condenser. In some condensers, the low-pressure feedwater heaters are mounted in the side of the shell. In this way, the extraction linesfrom the low-pressure turbines are piped within the shell to the feedwater heaters to reducepressure losses. The exhaust from the feedwater pump turbine is also piped to the condensershell.

A vacuum is produced in the condenser by the condensation process and the specific volumechange from steam to a liquid. A low condenser vacuum corresponds to a low steam saturationtemperature. The total work done by steam flow through the turbine is proportional to thedifference between the temperature of steam entering the turbine and the saturation temperaturein the condenser. Therefore, the lower the saturation temperature, the more work that is done bythe steam in the turbine. The more work that is done in the turbine, the greater the thermalefficiency 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, thevolumetric flow is high. As a result, the condenser tube arrangement must be opened rather thancompacted in order to allow steam flow into the inner region of the tube bundle. A typical tubearrangement is shown in Figure 2-2. The tube pattern and shell volume is designed to minimizethe steam side pressure drop. A cruciform region in the middle of the bundle is void of tubes andforms a passageway to the circulating water inlet end of the condenser. This is to vent non-condensable gases that can accumulate during condensation of the steam. This is one design andcondenser manufacturers locate the non-condensable vents based on a number of arrangementsand bundle geometry factors.


Tutorial

2-3

Figure 2-2Condenser Tube Arrangement [1]

Condensers must continually vent non-condensable gases to prevent air binding and the loss ofheat 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. Non-condensable gas has a tendency to flow to the coldest area. This area is typically the circulatingwater inlet region of the condenser. This tendency occurs because the partial pressure of thecondensing steam is lowest in the cold region. Having the air outlet at the circulating water inletmight not be possible with all condenser bundle designs. Steam jet air ejectors and/or vacuumpumps establish a vacuum in the condenser before start-up and pull non-condensable gas withsome steam from the condenser during operation.


Tutorial

2-4

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

2.2 Rankine Cycle [2]

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

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


Tutorial

2-5

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 thesteam.

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 steamto a liquid to pump the condensate through the feedwater heaters and then to thereactor/boiler.

One of the purposes of the main condenser is to condense low-pressure turbine exhaust steam toenable maximum expansion of steam in the low-pressure turbine. An increase in condenserpressure 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 areain Figure 2-4, provides more available energy for expansion through the turbine (represented bythe 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 adissolved gas in a solution is directly proportional to the partial pressure of that gas in thefree space above the liquid. Deaeration or removal of the dissolved oxygen from water takesplace by the reduction of partial pressure of air in the surrounding atmosphere. Condensate isthen reheated to a temperature above the point that oxygen entrainment will occur. This canbe accomplished by using steam spargers or bubbling steam through the hotwell. Chemicalcompounds are added to the feedwater to remove the last traces of oxygen. Oxygen and othernon-condensable gases released in the condenser are then removed through the steam jet airejectors 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 condensatepumps that return the condensate to the feedwater system. In this way, the condensate issaved and returned to the system.

For a BWR unit, the main steam bypasses the turbine after a unit trip and enters thecondenser. Pressure reduction of the main steam before entering the condenser, anddispersion of flow in the condenser, might be accomplished by a series of orificed plates orpipes. In addition, the short-lived radionuclides in the steam decay in the condenser. Whenthe condensate is pumped to the feedwater system, the radiation level is decreased.


Tutorial

2-6

x Providing a leak-tight barrier between the high-grade condensate and untreated coolingwater. The condenser tubes and tubesheets act as barriers between the relatively impurecooling water and the high-grade condensate. Due to the vacuum inside the condenser, anyleakage will cause contamination of the condensate with the cooling water. This can lead toan increased corrosion rate in the steam generator/reactor/boiler. Though prevention ofcirculating water in-leakage is imperative in all cooling water systems, it becomes criticalwhere 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 backpressureon the turbine. The ingress of air and other non-condensables into the condenser shell canaffect thermal performance. The air-removal systems and their auxiliary equipment routinelyremove these gases. When excessive amounts of air are in the shell side, then the condenserpressure is increased. The effect of increased condenser pressure lowers the thermalefficiency of the turbine. In addition, high dissolved oxygen concentrations in the condensatecan 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 pressurepoint in a steam cycle, it is the most logical collection point for various condensate vents anddrains. The incoming vents and drains are usually located at a higher elevation above the tubebundles in a condenser. By the time the fluid reaches the hotwell, it is sufficiently heated anddeaerated.

x Providing a convenient place for feedwater makeup. The cold makeup water dischargeline is located above the tube bundles. The make-up fluid is heated and deaerated before itreaches the hotwell.

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

2.4 Condenser Types [3]

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

x The number of compartments, usually one compartment for each set of turbine two-flowexhausts

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 seriesthrough each shell


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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 atransverse 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 thetubes is possible. On larger units, a divided waterbox is provided (Figure 2-5c) where access toone box at a time is possible with the unit on-line at a reduced load.


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Figure 2-5Single-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 aretwo tube bundles, one on top of the other. Circulating water flows through the upper waterboxinto the top tube bundle, reverses direction by 180 degrees and flows back through the lowertube bundle, and exits through the lower waterbox. This style allows higher flow velocity andtemperature rise.


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Key O&M Cost Point

Two-pass condensers are selected when the cooling water is a premiumquantity, installation space is restricted, or the plant layout dictates that theinlet and outlet must be at the same end of the condenser. In plants withcooling towers, a two-pass condenser can reduce the size and, therefore, thecost of the cooling tower.

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

2.4.3 Two-Compartment, Single-Pass, Transverse Flow, Parallel DesignCondenser

Two compartment condensers are designed in several configurations. Each compartment can bea single-pass type with the compartments piped in parallel. This gives a common water inlettemperature. Assuming the exhaust flow is equally divided between the compartments, thebackpressure in both compartments will be approximately the same.

2.4.4 Two-Compartment, Single-Pass, Transverse Flow, Series DesignCondensers

The two compartments might be piped in series as shown in Figure 2-7 for a fossil unit. Thewater leaving the first condenser compartment is connected to the inlet of the secondcompartment. The inlet and outlet water temperatures and backpressures for each compartmentwill be different. The first shell will receive the coldest cooling water and, therefore, will havethe lowest pressure and the lowest saturation temperature. Condensate from the firstcompartment is pumped to the second compartment. This results in a condensate temperature ashigh as in a single-pressure condenser.


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Figure 2-7Two-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 theturbine axis as one continuous flow path. This longitudinal design requires fewer waterboxes andthe 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 tubesfor maintenance.


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

2.4.6 Three-Compartment, Single-Pass, Transverse Flow, Parallel DesignCondenser

Three-compartment condensers consist of several single compartment condensers of the once-through type arranged in parallel. Most often these compartments have divided waterboxes.

2.4.7 Three-Compartment, Single-Pass, Transverse Flow, Series DesignCondenser

Figure 2-9 shows a three-compartment condenser arranged in series. The backpressures and inletand outlet water temperatures in each compartment are different.


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Figure 2-9Three-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 inthe longitudinal design can be 100 feet (30.5 meters) long. A large space is needed in the plantlayout for cleaning and removal of tubes for maintenance.

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


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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 thisarrangement, the inlet tubes run from the inlet waterbox through the first compartment and to awaterbox in the center of the second compartment. A separate tube bundle runs from the centerwaterbox to the third compartment and to the outlet waterbox. This is shown in Figure 2-11.

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

Key O&M Cost Point

Generally, multi-compartment condensers lower average backpressure inthe low-pressure turbine without a significant decrease in the temperature ofthe condensate leaving the hotwell. The lower condenser backpressuremeans increased turbine efficiency.

2.5 Condenser Components [4]

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

x Shell

x Hotwell

x Waterbox

x Tubesheet

x Tubes

x Air-removal equipment


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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 onlydesign code applicable to condensers in the utility industry is the HeatExchange Institute (HEI) standards.

The design pressure of the shell is 30 inches Hg (76.2 cm Hg) vacuum and is suitable for anemergency internal pressure of 15 psig (1 kg/cm²). The shell is constructed of carbon or stainlesssteel plates welded together. Shell pressure boundary plates, support plates, and welds shouldhave a 1/32-inch (794 nm) corrosion allowance on each side exposed to steam/water in thecondenser. The shell is hydrostatically tested after field assembly. The shell might be joined tothe turbine exhaust casing by an expansion joint. The joint might be a metal bellows orrubberized 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 hotwellis made of the same material as the shell and is an integral part of or is connected to the bottomof the shell.

The hotwell is designed to have a minimum available volume sufficient to contain all of thecondensate produced in the condenser in a period of one minute under conditions of maximumsteam load.

Suction is provided from the hotwell to the condensate pumps to deliver the condensate into thefeedwater system. Because the hotwell is the lowest pressure point in the steam cycle, it is thecollection 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 stainlesssteel, copper nickel, or titanium. Cast iron is more resistant to corrosion but cannot be easilyrepaired. Internals of the waterbox are generally coated or cathodically protected to minimizecorrosion. The waterbox is designed to the pressure of the circulating water system. The criticaldesign aspect of a waterbox is its access. There should be one manway at the bottom of the boxand one at the top. Two manways at the top are preferable. Waterboxes are either bolted orwelded 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 supportthe total load of waterbox pressure, the waterbox, or water in the waterbox. Condenser tubesshare this load with the tubesheet. The primary function of the tube-to-tubesheet joint is to


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prevent leakage of cooling water into the condensate. Tube-to-tubesheet joint leakage tends to besmall 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 steelor titanium.

2.5.5 Tubes

Alloy steel condenser tubes are manufactured by forming alloy steel strips and then weldingthem 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 theextrusion 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 anoxygenated, ammonia-rich environment. This environment promotescondensate corrosion (grooving) in copper-alloy tube materials. For thisreason, the tube materials in this section are made from a more corrosion-resistant 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-condensablegases from the condenser. The air-removal section is normally located toward the bottom of, ordeep within, the tube bundles where the condensate and water vapor temperature tends to belower. There, the vapor becomes subcooled with respect to the saturation temperaturecorresponding to the pressure of the vapor. It is a region of tubes surrounded by a shroud (roofand 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. Thelower tube temperature and associated vapor subcooling tends to cool any air or other non-condensables present. This reduces their specific volume, condenses the extracted water vapor,and concentrates the gases within the protected area. These actions create a scavenging processto remove non-condensables from the region under the shroud. The exhauster located at the otherend 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/orvacuum pump. Section 2.5.6.1 covers the steam jet air ejector and section 2.5.6.2 covers theliquid ring vacuum pump.


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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 forthe ejection of air and other non-condensables from a condenser compartment. The steam jetflows 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 passedthrough a diverging cone or diffuser. The resulting increase in pressure enables the mixture to bedischarged against a pressure that is higher than that of the entraining chamber. The main steamis throttled and connected to the nozzle that is on the same axis as the mixing section anddiffuser. The basic construction of a steam jet ejector is shown in Figure 2-12.

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

A variety of air ejector system configurations exist. Some of the configurations are singleelement, 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 orthree ejectors in series to obtain the desired vacuum.

In the condensing designs, an intercooler is located between the ejectors to condense the steamleaving the preceding ejector. These coolers lower the temperature of the steam leaving theejector stage and reduce the volume before entering the next stage. The aftercooler is used tocondense the steam before leaving to the vent system. Figures 2-13, 2-14, and 2-15 show thedifferent ejector configurations.


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

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


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Figure 2-15Parallel 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-removalsystems for steam surface condensers. The liquid ring vacuum pump is a rotary, positivedisplacement pump using a liquid as the principal element in gas compression. It is not unusual


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

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


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3 TROUBLE-SHOOTING

This section on trouble-shooting condenser problems deals with the operating conditions ofincreased condenser pressure, air binding, and air-removal equipment problems. The detectionand location of a leaking tube is covered in Section 7.5 of this report. Excessive air in-leakage iscovered 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 thepressure at the turbine/condenser flange. These pressures and temperatures might not be equaldue to the condenser neck design. In most discussions, the condenser pressure and turbinebackpressure are considered the same thing. Turbine backpressure is important because it affectsthe final stage, turbine blade performance.

Two indications that the condenser might not be performing in accordance with its design, giventhe current cooling water inlet temperature and flow rate, are:

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

x Increased Level of Dissolved Oxygen (DO). The problem resulting from high dissolvedoxygen 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 andthe 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 oneanother. Some of the above parameters are also affected by water side conditions and will beincluded in the following discussion.


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Figure 3-1 shows a diagnostic flowchart for high condenser pressure. The following discussiondetails 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 withan 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 macrofoulingwith normal waterbox level.

An increase in condenser pressure, an increase in the TTD, a normal cooling water 'T, and ahigh 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 lowflow rate, the air-removal problem can be caused by inadequate design, poor performance, lowload 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 bycondenser pump seals, hotwell manway gaskets/flanges, and strainer spool piece problems orhigh 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 turbineseals, 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 coolingwater temperature difference indicates a high inlet water temperature. A high temperaturedifference indicates low cooling water flow. If the head on the cooling water pump is high, thenthere 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 beexamined. If the motor amps are decreasing, then the pump might be experiencing wear orcorrosion on the pump impeller and casing. If the motor amps are fluctuating, then the pump canbe cavitating. Cavitation can be caused by silt or macrofouling in the intake or the intake waterlevel might be too low. If the motor amps are increasing, then there might be other pump orcasing damage.

Key Technical Point

Backpressures lower than design tend to improve heat rate. Therefore, lowerbackpressures are desirable. However, the backpressure should not be solow that it is the cause of unnecessary condensate subcooling (see thediscussion in Section 4.1.1).

The upper limit on backpressure is given by the turbine manufacturer, typically in the 4.5 to 5.0in. HgA (11.4 to 12.7 cm Hg) range.


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Figure 3-1Condenser 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 thespace between the tubes is filled with air. Although this condition can occur in many areas, it isprimarily found in the air-removal zone when the air in-leakage rate exceeds the capacity of theair-removal equipment. The possible causes of air binding are:

x Steam bypassing the air cooler zone of the condenser. When the steam bypasses the air-removal zone through cracks in the piping or the seal plates, the steam leaking into the air-removal piping reduces the amount of air removed by displacing air. This raises the vacuumpump 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 ejectoris operating or the air-removal sections of the low-pressure and high-pressure condensers aretied together, then air binding can occur. Removal of the air in the high-pressure condenserdisplaces the air that could have been removed from the low-pressure condenser with higherpressure steam.

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


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further decrease in air-removal equipment capacity. The pressure drop between the condensershell pressure and the pressure at the suction of the air-removal equipment can be more than1 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 pumpoperation. An additional vacuum pump is placed in service while monitoring condenserpressure, load, and circulating water inlet temperature. If the addition of another vacuumpump 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 bescheduled. The condenser pressure should drop with decreasing load. It drops less rapidly ifthe condenser is air-bound. A curve demonstrating how an air-bound condenser behaves atlow load is shown in Figure 3-2.

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

x Air in-leakage rate versus pressure. While holding the load constant with air-removalequipment in service, a measured rate of air, increased in steps, can be added to thecondenser. 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 responseto controlled air in-leakage when the condenser is air-bound and when it is not. Cautionshould be taken when using this method because recovery can be difficult and there is thepotential to lose control of the air in-leakage.


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

x Outlet Temperature Stratification. A grid of temperature detectors can be installed at theoutlet of the condenser to identify regions of low heat transfer. Because air binding preventsthe entrance of steam into the regions of the tube bundle where air binding is occurring, thecirculating water temperature rise in the air-bound regions is reduced. This method can becostly 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 thesteam jet air ejectors. Section 3.3.6 and 3.3.7 concentrate on problems with the liquid ringvacuum pumps (LRVPs).

3.3.1 Poor Vacuum

Poor condenser vacuum caused by problems with the steam jet air ejectors is indicated by one ormore of the following conditions:


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x Low steam pressure. Each ejector nozzle is specially designed for the steam pressurespecified for the application. If the pressure is less than design, the system cannot achieve thedesired 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 forpossible nozzle changes to allow for the lower steam pressure.

2. Check whether there are any obstructions in the steam supply system that might becausing 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 forsaturated steam. Note that saturated steam passing through a pressure-reducing valve willbecome superheated. Steam supplied to a steam jet air ejector should never contain moisturebecause this can cause erosion as well as performance problems. If the motive steam is notdry saturated but is superheated, the ejector manufacturer should be alerted. The design of thesteam 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 tobecome clogged than those designed for lower pressures. Properly designed steam ejectorswill allow the steam nozzle to be cleaned in place. An alternative method is to remove theentire steam chest assembly. Then remove the plug located on the steam chest and blow outany chips or scale from the nozzle end.

x Total condenser air in-leakage. Check the main condenser air in-leakage with the probeprovided on the discharge of the after-cooler for a condensing ejector system. If air leakage isexcessive, check the vacuum system for tightness.

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

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

x Poor main condenser operation. When condenser equipment has been in operation forextended periods of time, deterioration in performance is often attributed to the ejectorvacuum system. However, the main turbine condenser might itself be the source of theproblem. Some of the possible causes include high cooling water temperature, insufficientcooling water flow, or excessive fouling of the condenser tubes.

x Leaking air inlet isolation valves. In a twin-element steam jet air ejector, poor condenservacuum can result when the ejector performance is degraded because of leakage through aseemingly closed first-stage air inlet valve. This leakage causes a recirculation flow to occurbetween 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 performanceand condenser vacuum might be improved by switching elements.


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3.3.2 Gradual Loss of Vacuum

Some of the causes for a gradual falling off in vacuum could be attributed to the followingproblems:

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

x Improper operation of condensate trap. To correct this problem, the trap should bedisassembled 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 onthe vapor side of the inter- and after-coolers. In order to locate the tube that is leaking, it willbe 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 thepresence of wet steam. The steam piping should be examined to ensure that there are no lowpoints 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 causedby a corroded or eroded nozzle, condensate trap mis-operation, clogged loopseal 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 turbinecondenser. At low turbine loads, the condensate flow might be insufficient to sustain propercooling within the ejector system. If no alternative source of freshwater supply is available toreplace the condensate flow, a loss of vacuum can result, along with high discharge temperatureson 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 benecessary to check for any one or more combinations of these conditions if trouble isexperienced with the ejectors.

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


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x Steam nozzles plugged with scale. A scale deposit might form in the throats of the steamnozzles, consisting of chemicals used in the treatment of the feedwater. When this occurs, thescale 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 inter-cooler with water can be caused by faulty drainage. This can usually be established byobserving the temperature of the intercooler shell.

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

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

x Loss of the water seal in inter-cooler drain loop. Loss of water in the drain loop takesplace occasionally in installations where the vacuum in the system is subject to suddenfluctuations. A sight glass is recommended on the inter-cooler drain loop to show whetherthe loop is properly sealed when the ejector is in service. This sight glass should be as nearthe bottom of the drain loop as possible. If the water is visible anywhere in the glass, the loopis properly sealed.

However, if no water is visible or if it surges violently, the indications are that the drain loophas become unsealed. When this happens, some of the air removed from the main condenserby the primary element is recirculated and flows back through the drain loop to the maincondenser, thereby reducing the vacuum.

To re-establish the seal in the drain loop, it is necessary only to close the valve in the drainloop line provided for this purpose. This valve usually is located close to the condenser. Thisvalve must be closed for the short period of time required to form sufficient condensate andrefill the loop. After the water again shows at the top of the gage glass, the valve should beopened very gradually. If the valve is opened too quickly, the difference in pressure willcause the water to surge and again unseal the loop. In certain cases, some drain loops have atendency 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 openingshould be enough to pass the condensate at all times.

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


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3.3.5 Ejector Field Testing

It is difficult to check the operation of an ejector in the field, but some testing can beaccomplished by checking the shut-off performance of each ejector. It is recommended that testsbe performed when the unit is first placed in operation and that these readings are kept on file forfuture reference.

If an ejector is operating satisfactorily but suddenly loses vacuum and then re-establishes itsperformance 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, itmight be an indication of internal wear. Ejectors should be inspected periodically andcomponents 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 inFigure 3-4.


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

The first response to a poor condenser vacuum is to check whether a sufficient number of pumpsare in operation. The air in-leakage is then checked and steps taken to reduce the leakage ifneeded. If modern instrumentation is available, air in-leakage and pump capacity in terms ofeither ACFM (actual cubic feet per minute at operating conditions) (cubic meters per hour) ormass flow rate can be checked. If the capacity is low, the pump will need attention. This includesadjusting the operating conditions or performing maintenance. Assuming the above conditionshave been met, the separator level should then be examined and, if low, makeup water should beadded.

Air leakage at the LRVP shaft packing gland should be checked. If a leak is suspected, a hosewith a small stream of water can be sprayed on the rotating shaft to temporarily stop the leak. Ameasurement of the disappearance of the leak can be made using the LRVP exit rotameter or bymeasuring the mass flow rate or ACFM (cubic meters per hour) capacity on the suction side ofone LRVP, as mentioned above.

If problems persist and the pump vacuum is higher than the vacuum in the condenser, theremight be a restriction or a closed valve between the condenser and the pump. Similarly, if theseal water flow is low, there is probably a restriction within the seal water piping.


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Finally, if the seal water temperature is high, it probably indicates a problem with the heatexchanger. 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 ExchangeInstitute lists the following checklist of operating variables:

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

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

x Seal water flow. Reduced seal water flow will result in an increase in temperature rise and areduction 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 resultof restrictions between the vacuum pump and the condenser, causing the vacuum pump tooperate at a higher vacuum than necessary.

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


4-1

4 PERFORMANCE

Key O&M Cost Point

Condenser performance significantly affects the heat rate and generationcapacity of a power plant. A 1 in. Hg (2.5 cm Hg) increase in turbinebackpressure can result in a 2% increase in heat rate.

Due to changing plant conditions of cooling water flow rates and water inlet temperatures, thecondenser backpressure is not a true indication of its efficiency. Condenser performanceevaluation requires extensive data collection and analysis. Deviation from the designperformance 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. Section4.7 includes information on condenser performance calculations and monitoring.

Condenser fouling has a profound effect on condenser performance and is caused by severalmechanisms. 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, theheat transfer surface is circular with the inner surface smaller than the outer surface. When


Performance

4-2

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

.1111

31 2etc

KKKKe

�� (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 thefact 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 onthe inside and outside of the tube need to be taken into account in calculating the effectivethermal coefficient of the composite surface. Film coefficients are dependent on the fluidtemperature, density, viscosity, specific heat, flow velocity, and shape of the heat transfersurface.

4.1.1 Condensate Subcooling [3]

Heat transfer theory indicates that the mean temperature of the condensate at the tube surfaceand, subsequently, the temperature of the cooling water, must be less than the temperature of thecondensing water vapor. This is necessary for heat to flow from the condensing vapor throughthe tube walls and into the cooling water. As the vapor progresses through the bundle, the heattransfer coefficient of the rows in the tube bundle tends to fall from row to row. This tends tofurther reduce the mean temperature of the condensate on each tube. There is an inherenttendency for the temperature of the condensate, and in particular on the tube ends nearest theinlet waterbox, to be below that of the exhaust vapor temperature.

When the temperature of the cooler condensate regions is below the exhaust vapor temperaturethen these condensate regions are considered subcooled. In these regions, there is a markedincrease in oxygen solubility. To minimize the effects of condensate subcooling on certainsections 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 thetemperature of the condensate as it cascades down the tube bundles.

The ultimate degree of condensate subcooling that is experienced varies with load and coolingwater 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


Performance

4-3

at the suction of condensate pumps (for example, due to a shallow hotwell depth), then theslightly lower temperature also helps to reduce pump cavitation. This is because the condensateat saturation temperature is more likely to flash into steam.

Condensate accumulates in the hotwell below the condenser tubes. Normally, the water level inthe hotwell is maintained below the condenser tubes. Either by intention or by malfunction oflevel control, the hotwell level can rise and flood the lower tubes. This causes the condensate tosubcool below the saturation temperature corresponding to the condenser pressure. It can causeincreased levels of dissolved oxygen and corrosion of the bottom condenser tubes. It also resultsin 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 a0.05% increase in heat rate.

Some plants prefer to operate with condensate subcooling because it reduces cavitation in thecondensate pumps. The need for this practice is questionable because many condensate pumpsare located well below the hotwell to minimize cavitation or are designed to operate in acavitation mode.

4.1.2 Hotwell Subcooling [3]

To understand hotwell subcooling, consideration should be given to performance of the turbineand plant design. It is a design objective that the condenser should remove the latent heat ofvaporization from the steam. However, the condenser should not remove any more heat thanthat. At full load, it is desirable that the steam leaving the final stages of the low-pressure turbinecontain a small amount of condensed water in the form of a mist. To maintain these two states ofwater and vapor, the operational conditions of the condenser circulating water flow rate andtemperature are considered.

Variations in the nominal range of circulating water temperature or flow rates will cause theturbine exhaust steam quality to change. As an example, if only the circulating water temperaturedecreases then the average hotwell temperature will decrease. This causes a reduction in turbinebackpressure. This decreases the moisture concentration at the final turbine blade stage. Whenthere is no longer any water in these final stage turbine blades, the steam exiting the turbineexperiences choked flow that limits the flow of steam.

More thermal energy removal by the condenser, either by lower circulating water temperature orhigher flow rate, results only in subcooling of the hotwell condensate. This allows the hotwelltemperature to fall below the temperature of the turbine exhaust steam. Because of the dry stateof the turbine exhaust, the steam can be considered superheated. This hotwell subcooling isuneconomical because the excessive amount of heat removed by the subcooling needs to berestored in the steam generator or by adding more fuel to the boiler. In addition, subcoolingsignificantly increases oxygen solubility.


Performance

4-4

4.2 Condensing Duty [1]

The condensing duty is the total heat transferred to the condenser circulating water. Thecondenser duty can be calculated by subtracting the steam cycle side non-condenser heat flowsfrom the energy delivered to the steam cycle, Qt. Typically, the non-condenser heat flows aregenerator electrical output, generator losses, auxiliary steam, and steam-driven feedwater pumps.Steam generator blowdown from PWR plants should also be considered. The accuracy of thiscalculation depends very much on the accuracy of the instrumentation used to measure theparameters 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) (eq. 4-4)

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)


Performance

4-5

Condensing duty can also be calculated using turbine exhaust flow and enthalpy into thecondenser

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 theseparameters be estimated using turbine electrical output and the turbine heat balance or thermalkit. This method is inherently inaccurate.

4.3 Heat Transfer Coefficient [3]


There are two principal ways of estimating a condenser’s currentperformance, the Heat Exchange Institute (HEI) method [6] and the ASMEmethod [7]. Both compare the current value of the effective heat transfercoefficient (Ueff), computed from present steam and water temperatures andcooling water flow rate, with a reference value calculated according to one ofthe two procedures.

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

A*LMTD

QUeff (eq. 4-6)

where,

Q = Heat Rejection Rate, Btu/hr (j/s)

A = Tube Surface Area, sq. ft. (sq. meter)

¸¹

·¨©

§

�

�

�

inv

outv

inout

TT

TT

TTLMTD

lnLog mean temperature difference in ºF (ºC) (eq. 4-7)

Tv = Vapor temperature in shell in ºF (ºC)


Performance

4-6

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 compartmentbackpressure. For multi-compartment condensers, this set of information is required for eachcompartment.

Deviations in the condition of the condenser from design because of fouling or air in-leakagewill 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 thatcorresponds to the set of operating conditions consisting of condenser duty, cooling water flowrate, and inlet water temperature. For a given duty, if the cooling water flow rate falls or thewater inlet temperature rises, the backpressure will also rise. A similar increase in backpressurewill occur if the tubes become fouled or the concentration of non-condensables in the shell spaceincreases. Both conditions tend to decrease the effective tube heat transfer coefficient. Theconcentration of non-condensables can rise if the air-removal equipment becomes degraded or ifair 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 transfercoefficient and is a function of tube water velocity, inlet water temperature, tube material, tubegauge, and the cleanliness factor. Tables and curves in the HEI Standards for Steam SurfaceCondensers [6] allow the appropriate values to be selected, either according to the design data setor the operating data set. Let:

UHEI = HEI corrected heat transfer coefficientU1 = HEI uncorrected heat transfer coefficientUref = HEI reference heat transfer coefficientFW = Correction factor for water inlet temperatureFM = Correction factor for tube material and gaugeFC = Correction factor for cleanliness

Then

UHEI = U1 x FW x FM x FC (eq. 4- 8)

And

Uref = U1 x FW x FM (eq. 4-9)

Design values of cleanliness factor FC are usually around 85%, but values as high as 95% havesometimes been used.


Performance

4-7

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

ref

eff

U

UFCeff = (eq. 4-10)

To evaluate the current state of the condenser, the value of FCeff calculated from Equation 4-10has to be compared with the design cleanliness factor (FC) stated in the original condenser designdatasheet provided by the manufacturer. However, experience has shown that the data containedin these design data sheets are not necessarily consistent. The stated value of the designcleanliness factor should be verified from the complete set of design data.

These cleanliness factor calculations are most reliable when the condenser is operating close toits design or full load conditions. There is evidence that the design cleanliness factor varies withload. To evaluate performance under partial load conditions, the relationship between the designcleanliness 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 designcleanliness factor; this should be taken into consideration when evaluating the performance ofeach compartment.

4.5 ASME Method [3]

The ASME method of calculating condenser performance uses an estimate of the single-tubeheat transfer coefficient as the reference value. The value for a clean condenser is calculatedfrom:

1

1−++

=ftw

ASMEhRR

U (eq. 4-11)

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

=

i

o

m

ow

d

d

k

dR ln

24(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)


Performance

4-8

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

»¼

º«¬

ª»¼

º«¬

ª»¼

º«¬

ª

i

oi

pt

d

d

V

d

Ck .R

835.0

165.0

462.0538.0835.0

373.0

04503570U

P

(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 temperaturethat corresponds to the compartment backpressure and is calculated from:

25.023

7250 »¼

º«¬

ª

'

T) ( D

g k.h

of

f

f

P

OU(eq. 4-14)

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 factorand is calculated from:

ASME

eff

eff

U

UPF 100 (eq. 4-15)


Performance

4-9


The ASME reference value of the heat transfer coefficient is a single-tubevalue and the HEI reference value is an overall tube bundle heat transfercoefficient. The value of the effective cleanliness factor (HEI method) isgreater than the corresponding performance factor (ASME method) on thesame condenser. It has also been observed that the design value of the ASMEperformance 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 designcondenser pressure of 1.5-inch HgA (3.8 cm Hg) and a turbine inlet pressure of 1,000 psia (6.9megapascal). Figure 4-1 shows that the last stage turbine bucket (LSB) loading has a significanteffect on change in heat rate due to changes in condenser pressure. If the bucket loading, definedas design generator output in kW/sq.ft is high, then the bucket losses are high. High bucketlosses decrease with increasing turbine backpressure and offset the loss in thermodynamicefficiency that occurs with increasing turbine backpressure. Most nuclear turbines have high laststage bucket loadings because turbine configurations are limited to three or fewer low-pressureturbines.

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


Performance

4-10

4.7 Performance Monitoring [1,10]

Key Technical Point

The following parameters should be measured when monitoring condenserperformance: inlet and outlet tube side pressure, inlet and outlet coolingwater temperature, impressed cathodic protection settings, condensercleanliness 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 microbiologicallyinduced corrosion, fouling of the tubes, scaling, deposit build-ups, and so on. Main condensersare considered to operate continuously in severe conditions. Performance monitoring every weekis recommended to address the vulnerability to sudden onset and propagation of corrosion andfouling.

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 aninternal 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 orlow cooling water flow. In either case, the outlet temperature increases, raising coolingtemperature 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 inletpressure, and cooling water temperature rise across the condenser. Pressure and temperature bothtend 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 coolingwater inlet temperature or flow, then the problem is most likely an increase in tube fouling or abuildup of non-condensable gases. Determining whether tube fouling or non-condensable gasbuildup causes the pressure increase requires additional diagnostics.

If cooling water flow decreases and there has been no change in circulating water systemconfiguration, such as reduction in the number of circulating water pumps, then tubesheetfouling or tube plugging by debris is likely. The latter can be a significant problem when there isdebris in the cooling water intake.

Tube fouling requires periodic mechanical or chemical cleaning of the inside of the condensertubes. 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 chemistrycontrol program. See Section 6, Cleaning, for more details.

Another condenser parameter that is often monitored is hotwell temperature. Ideally, thetemperature should be near the saturation temperature of water at condenser pressure. Thehotwell temperature might be a few degrees above saturation as the result of a design that ducts


Performance

4-11

the feedwater pump turbine exhaust below a perforated plate in the hotwell. If the hotwelltemperature is significantly lower, there can be a heat rate penalty due to additional heat loss tothe 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 performancemonitoring. It is a way to anticipate adverse conditions and to plan corrective action in advanceof 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 trendlines. Data must be entered manually unless the PC is connected into a plant data networkand the network contains the data points needed for trending. Manual data entry mightconsist of data entry to a hand-held data collection device that can be downloaded to a PCprogram.

x Trend using the plant process computer if the computer receives and stores the appropriatedata points. Algorithms to compute trends are available as standard packages or can bedeveloped 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 programbased on expert system technology and the Thermal Performance Diagnostic Manual, NP-4990-V1-3, April 1987. The NTPA is an interactive, heat rate diagnostic expert system thatprovides performance engineers with assistance in identifying causes of lost powergeneration. One diagnostic area is the condenser.

2. EPRI has a software solution product, The Heat Exchanger Workstation-CondenserApplication (HEW-CA) initiated in April 1996 [11]. The software includes the following fivetightly integrated applications:

x Diagrammer – to specify the schematic and design of the condenser

x Performance Analyzer – to compute condenser performance parameters based onoperating conditions

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

x Tube Failure Advisor – to provide failure mechanism analysis based on operating/designconditions

x Operations and Maintenance Manual – to provide an electronic, fully indexed referencesystem


Performance

4-12

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 condenserperformance. Figures 4-2 and 4-3 show the steam and water side condenser instrumentation.

Figure 4-2Typical Steam Side Instrumentation [13]


Performance

4-13

Figure 4-3Typical Water Side Instrumentation [13]

The following are parameters that need to be measured and a suggested form of instrumentationto accomplish each task.

4.9.1 Condenser Pressure

Turbine backpressure is typically measured by a series of basket-tip pressure-sensing deviceslocated in the exhaust hood. Measurement at this point does not accurately indicate condenserpressure, as defined by the HEI standards [1] as the absolute static pressure that is not greaterthan 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 wheresteam flow is uniform and perpendicular. However, the pressure is measured more accurately bya series of parallel-plate measurement devices located 1ft (30.5 cm) above the tube bundle anddistributed to obtain an accurate average pressure. According to the ASME Power Test Code onSteam Condensing Apparatus (PTC 12.2, 1975), approximately one measurement point for every100 square feet (9.2 square meters) of cross-sectional tube bundle area is required in the plane ofmeasurement, with a minimum of four measurement points. Basket tips should be installed at a45q angle from the vertical. Guide plates should be installed so that steam flow is perpendicularto 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 eachcompartment is suggested. Basket tip sensing lines should be sloped to avoid moistureaccumulation. The sensing line should be purged before each reading.


Performance

4-14

4.9.2 Air In-Leakage

Equipment typically used to measure airflow includes rotameters, pitot tubes, flow meters, andmultisensor probes.

The multisensor probe (MSP) is a standard instrument for measuring the amount of air in-leakage. A sensor is installed in each air-removal line leaving the condenser. This instrument hasbeen used with the tracer gas for locating air in-leakage. More information on this probe can befound in Section 7.2.2 of this guide.

Monitoring might consist of the placement of a rotameter at the discharge side of the vacuumpump/air ejector. Monitoring of airflow downstream of the air receiver is preferred because theair/steam mixture typically evacuated from the condenser has been separated. The air receiverseparates the steam/air mixture so that mostly air flows through the rotameter. If a separatingdevice is not present in the installed air-removal system, it is possible to calibrate the rotameterfor an air/steam mixture. Figure 4-4 is a picture of a rotameter.

Figure 4-4Rotameter Type Flow Meter [3]

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


Performance

4-15

Vane-type flow meters can be useful to establish base curves at various loads and condenserpressure 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 performanceand integrity. Dissolved oxygen in the condensate is usually measured at the discharge side ofthe condensate pump. It is preferable to measure oxygen concentration closest to the hotwell onthe suction side of the condensate pump. This, however, is generally not practical because thecondensate 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 orperiodic grab samples. The samples are taken from sampling connections on the condensatepump discharge and sent to a sample sink usually located in the water chemistry laboratory of theplant. The samples are generally analyzed by the color comparator method to determine oxygenconcentration. The major shortcoming of this method of analysis is the very slight colordifferences that occur between discrete oxygen concentration levels. Usually the colorcomparator kits are graduated in 5 ppb units. The major advantages of this method are speed andlow cost.

Analyzers with strip chart recorders can accurately measure dissolved oxygen concentration inthe condensate system. Typically, the analyzers consist of a readout panel/transmitter and an on-line probe.

When condensate flows through the sample probe, oxygen diffuses through a membrane and iselectrically reduced at the probe cathode. At the same time, an equal amount of oxygen isgenerated at the probe anode. Diffusion through the permeable membrane continues until theoxygen pressure on both sides of the membrane is equal. The current necessary to maintain thepressure equilibrium is converted by electrical circuitry to read the dissolved oxygenconcentration 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 alarmwhen 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 thedischarge 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 thesample pressure to less than 50 psig (345 kilopascals). The maximum allowable temperature isapproximately 175ºF (79ºC).


Performance

4-16

4.9.4 Hotwell and Condensate Temperature

The point where the condensate temperature is taken is critical. Many units take measurement ofcondensate temperature at the discharge of the condensate pumps. This measurement locationhas inaccuracies because condensate pump power input adds heat to the condensate. Thetemperature is most accurately measured at the condensate pump suction after some mixing hasoccurred in the suction piping. Mercury in glass thermometers and calibrated resistancethermometers or thermocouples can be utilized to accurately measure condensate hotwelltemperature.

4.9.5 Circulating Water Flow

Flow rate measurement might be required to verify the performance of the circulating waterpumps or to evaluate the condenser thermal performance. Most power plant circulating watersystems have substantial flow rates. Flow meters are not typically included in the original designand 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. Thedirect methods are best, but these are often limited by a plant’s arrangement. Applicable testcode 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 atracer can be labor intensive. The equipment cost is low, due to the availability of rentalequipment. Sonic flow testing has a high capital equipment cost because of the multipletransducer mounts required.

Circulating water flow can be very difficult to measure. This is generally because of largeinaccessible pipes and insufficient straight runs. Accessibility, coupled with required straightruns, 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, theiradvantages and limitations. It is important to note that the choice of one method over anotherrequires 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. Thesemethods require long lengths of straight and constant geometry conduit. Accurate measurementof a conduit cross-section at the measurement location is required.


Performance

4-17

An annubar is essentially a fixed multiple port pitot tube. Annubar applications are morecommon for smaller pipe diameters. The annubar application is a proven technique and has beenused in pipes of up to 12 feet (3.6 meters) in length. However, it should be carefully evaluatedbefore use in a circulating water system application. The recommended approach would be insitu calibration of the annubar by means of another high accuracy flow measurement techniquesuch as dye dilution or pitot tube traverse.

When a pitot tube or velometer is used, a series of point velocity measurements are integratedover the flow measurement cross-section. A pitot tube can be used where velocities are between4 to 15 feet per second (1.2 – 4.6 meters/sec). For lower velocities in large conduit sections, avelometer is the preferred device. Both devices require long lengths of straight conduit runs tominimize variations in flow direction and to establish a predictable boundary layer. For circularpipes, the diameter is traversed at two perpendicular locations with multiple measurement pointson each traverse.

Circulating water piping is often buried and inaccessible. If this is not the case and there is a longstraight run of pipe, pitot tube traverses will result in a highly accurate direct measurement. Thetraverses show the velocity profile across the pipe and, from this, the average flow can bedetermined. High accuracy can be achieved if the velocity profile is relatively flat. Thedisadvantage 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-acceptedmethod of measuring large flow rates typical of circulating water systems. Aerodynamicallyshaped 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 accuracyof 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 havingrelatively low velocity. For pipes more than 10 feet (3 meters) in diameter with velocities inexcess of 9 feet per second (2.7 meters/sec), the measurement is complicated by the tendency ofthe velometer to vibrate. Velometers require laboratory calibration for acceptable accuracy. Atypical 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 injectedupstream in the circulating water system at a known rate. Dye concentration is determined at apoint downstream with a fluorometer after adequate mixing has taken place. By factoring in thebackground fluorescence before injection, and the dye injection rate, the circulating water flowrate can be calculated quite accurately (within 2.0%) using a mass balance approach. The maindisadvantages are that the method is labor intensive and requires complete mixing of the injecteddye solution before it reaches the sampling point. The disadvantages are that the circulatingwater pipe section geometry is not a limitation and the method is low cost.


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A dye dilution test could be performed every two to three years to calibrate the pump curves. Thedye dilution method can also be used to calibrate other permanently installed flow measuringdevices. This method is becoming the most often chosen method due to the favorablecombination of high accuracy and low cost. In addition, a unit shutdown is not required. It isimportant 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 planein which the transducers lie is at a 45-degree angle to the pipe axis. The acoustic propagationtimes, both upstream and downstream, between each pair of transducers, are measured and anelectronic digital signal conversion results. By using several chordal paths, the ultrasonic flowmeter 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. Itis the algebraic sum of the static discharge head, the velocity head at the measurementconnection, 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 beinstalled 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 electricdrop line with measuring tape referenced to a temporary benchmark. The elevation differencebetween a piezometer water column and the water level in the pump bay is added to the velocityhead. This is derived from the flow measurement test and the circulating water pipe size tocalculate pump total dynamic head. Once the pump head capacity curve is verified, it can beindirectly estimated what the circulating water flow rate is by entering the pump curve with thetotal head to read the flow rate.

The pump curve accuracy can be verified by one of the more accurate methods of flow testingsuch 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 determinecirculating water flow by graphical method. The objective is to develop a relative condenser flowrate monitor using a differential pressure technique developed by Tennessee Valley Authority(TVA). This technique takes advantage of the fact that flow acceleration and flow separationcause a differential pressure to exist between the outlet waterbox and the outlet tailpipe. Becausethe Reynolds number of the flow is very high, the flow rate is proportional to the square root of


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the differential pressure. This technique is reportedly insensitive to fouling of taps because bothsets 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 beexpected. Because of the complex waterbox/tailpipes configuration and flow patterns, theconstant of proportionality cannot be determined theoretically. It requires an in situ calibrationby tracer dye method or other high accuracy flow measurement technique. This flow monitorwould provide the plant with a permanently installed condenser flow measuring device locateddirectly within the turbine building. Together with other condenser measurements, the plantwould 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 bymeans of resistance temperature detectors (RTDs) located in the pipes entering and exiting thecondenser waterboxes. There might be three or four RTDs per pipe, mounted on the pipe walland 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 thetemperature is usually consistent over the entire cross-section of the pipe. However, at the outletend of a condenser, concentric thermal stratification might occur several pipe diametersdownstream of the waterbox. Different bundle designs might cause different stratificationgeometry. If the RTDs are not located far enough downstream of the waterbox discharge forthorough mixing of the outlet water (that is, at least 10 pipe diameters downstream), they mightindicate a higher temperature close to the pipe wall, thus overstating the mean temperature. Forexample, an RTD extending 10 inches (25.4 cm) from the wall of the condenser tailpipe couldprovide an indication of outlet temperature that can be significantly higher than the meantemperature.

Pipe traversing using an RTD or thermocouple test probe can be performed to determine theextent of stratification and, thus, the accuracy of measurement. The traverse data can be used tocorrect the temperature indicated by the instruments. Other measurement methods can also beemployed such as thermocouples mounted on existing grids traversing the outlet pipe.

Another alternative is to provide temperature measuring sensors at different points in the cross-section of the pipe. Another method employs a crosscut temperature measuring device thatincludes a hollow tube filled with homogeneous oil and a wire located longitudinally through thetube center. By measuring the average temperature of the wire as the hollow tube is traversedthrough the circulating water pipe, the average temperature of the condenser discharge isobtained.

Generally, the thermowells are located in the discharge of the condenser due to stratificationconcerns. The crossover pipes are approximately 10 feet (3 meters) in length. The thermowellsare 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 locationaccess 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 pressuretaps on the inlet and outlet waterboxes. These pressure taps can be connected in individual ordifferential pressure measuring devices (differential pressure transmitters or mercurymanometers). The tap point should be located in a low-velocity zone. If the pressure taps arestatic-type taps located near the tubesheets, the measured pressure difference equals the pressureloss through the tubes. The tube velocity can then be determined by a graphical method. Theaccuracy is affected by tube fouling.

Because the differential method is not an absolute method, a calibration relating differentialpressure and circulating water flow rate is required. Using techniques such as the heat rejectionrate 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 thecirculating water is released during its path through the condenser. The condenser is normally thehigh point in the system and, together with the temperature rise across the condenser, thesaturation point of the oxygen dissolved in the circulating water is reduced. This release ofoxygen is not as severe in closed loop systems because the system operating pressure is oftenabove atmospheric pressure. In both cases, venting of the condenser waterboxes is desirable. Ifventing is inadequate, there will be a loss of complete submergence of the tube bundle that couldaffect condenser thermal performance. In addition, there could be additional flow resistanceimposed 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 portholeinstalled near the top of each waterbox. The need to periodically observe these levels is oftenneglected by operating personnel. This neglect is, in some cases, unavoidable because thedesigners frequently place the sight glasses in hard-to-reach locations. In other cases, the levelscannot be monitored because the sight glasses are not kept clean. Alternative level indicationinstrumentation could be applied to the waterbox. However, sight glass monitoring continues tobe the most cost-effective method.

An alternate type of sight glass is clear plastic tubing connected to both the top and bottom of thewaterbox. 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 thecirculating water in the tubes and, ultimately, with the heat transfer process. When there is anincrease in condenser pressure and a decrease in cooling water flow, fouling is the most likelycause. Other indications of fouling include an increased pressure drop and a reduction intemperature change for the inlet and outlet cooling water. Fouling impacts the output of the plantas it affects the condenser backpressure. The plant availability can be affected during seasonalchanges that produce annual fish runs, grass movement, seaweed deposition, accumulation ofleaves, and so on.

The deposits on the tube reduce heat transfer rates, decrease cooling water flow, and increasepumping 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 calciumcarbonate, 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 orinorganic debris such as sticks, leaves, fish, mussels, and so on. Microfoulingis the accumulation of deposits (inorganic scales or organic growths) on theinside of the tubes.

The following sections discuss macrofouling, microfouling, chemical treatment, waterregulations, chemical application methods, and a fouling monitor.

5.1 Macrofouling [14]

Organic or inorganic debris can occur from traveling screen carryovers or from growth oforganisms on the condenser and water conduit walls. The organisms eventually dislodge andplug the tubes. Macrofouling upstream of the circulating water pumps can reduce the availablenet 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 velocitiesaround 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 thisphenomenon while stainless steel and titanium tubes are less susceptible to this attack.

Organic debris left in the condenser tubes during outages decomposes biologically. This processof decomposition can be highly corrosive and produces compounds that can promote pitting or


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stress corrosion cracking in copper and brass alloy tubes. Pitting can also occur in copper nickeland in 300 series stainless steel under these conditions.

Prevention of macrofouling depends on site-specific conditions causing macrofouling. If thesource is debris such as seaweed or freshwater vegetation, then traveling screens at thecirculating water intake might prevent the debris from flowing into the condenser. If the source isan organism such as clams, then a biocide is needed. Many plants have the capability tobackwash the condenser to remove macrofouling. Strategies for backwashing depend oncirculating water conditions and trends in condenser performance.

To determine methods that control macrofouling problems, it is important to understand certaincharacteristics of various fouling agents. The freshwater and saltwater environments yielddifferent organisms that can cause fouling problems. Some of these organisms are discussed inthe following two sections.

5.1.1 Saltwater Organisms

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

x Mussels – Mussels are common fouling organisms that create severe problems at powerplants. The mussel shell is three-layered and the two valves of the shell are held tightly shutby a strong muscle. This tight closure of a thick shell and firm attachment to substrate bythreads make the mussel extremely difficult to move. If the adult is killed, the three- to four-inch shells might remain attached until physically removed. In some instances, musselsaccumulate in such dense aggregations on intake walls and in pipes that the weight pullslarge mats of mussels, shells and accumulated debris down to the floor of the structure. Thesedense mats can clog downstream components and the resulting debris can clog smaller pipesfarther along the system.

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

x Bryozoans – Bryozoans are colonial animals often mistaken for other organisms such asalgae, hydroids, corals, sponges, and so on. The bryozoan colony consists of numerous box-like compartments arranged in characteristic patterns. Each compartment contains anindividual animal having a tubular gut, a well-organized nervous system and otheranatomical 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 oftenresponsible for damage to traveling water screen panels at power plants.

x Tunicates – Tunicates are soft, sac-like animals growing either singly or flat, spreading formsthat 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 tubulesthat are an inch (2.54-cm) or more in length. They can grow in such masses that they coverlarge areas and can be more of a fouling nuisance than the barnacle.

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

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

x Debris – Mussel and barnacle shells are a common blockage problem in condensers. Thecarryover of grasses, leaves, shell fragments, and other waterborne debris can result in severeplugging 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 areascurrently populated by this organism and utilizing raw freshwater is vulnerable to cloggingby the Asiatic clam. The larvae can be carried through all standard screening equipment inpower plants.

x Algae – Various types of freshwater algae also create operational problems in circulatingwater systems. Being photosynthetic plants, algae species of concern at power plants onlygrow in areas exposed to light. The major problem caused by freshwater algae is the massiveinflux of mats or clumps that occur seasonally or after storms at many sites. The debrismatting can become so severe that spray washes cannot remove it. Manual brushing or evenburning of the debris might then be required.

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

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

x Debris fouling – Grasses, leaves, trees, branches, rocks, sand, and silt can cause problems inintake 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 andalternate 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 protectthe condenser and the circulating water system from macrofouling. A conventional power plantintake is shown in Figure 5-1.


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Figure 5-1Power Plant Intake Schematic [14]

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


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In the circulating water piping system, debris filters have been installed to supplement intakescreening. These filters are commonly located upstream of the condenser inlet waterboxes.Similarly, strainers are used in service water and screenwash systems. Condenser backwashrepresents 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 largedebris. In some plants, racks are located at the entrance to a cooling canal; at others, the racks arelocated 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 ofthe intake. Typically, trash racks consist of welded bar subpanels bolted to welded structuralsteel frames to form racks that are lowered into position in steel guideways embedded in theconcrete. Racks range from 5 feet to 15 feet (1.5 to 4.5 m) in width and are usually supported byconcrete piers. Trash racks can extend below concrete curtain walls that act to deflect largedebris and ice, or are located downstream of the curtain wall. The racks can be set vertically orinclined up to a 1-to-5 slope.

In cases where large debris (such as tires or trees) is encountered, another set of trash racksspaced 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. Thenature of this operation is such that station personnel clean racks only when the racks areconsiderably clogged with debris. Alternatively for light debris, some stations use cable-operatedrakes as shown in Figure 5-2.


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

The rack is cleaned by a single rake that is mounted in a carriage assembly. The rake carriage israised and lowered by two pair of cables operating from a drum hoist. The operator controlsclosing and opening of the rake teeth, lifting and dumping of the loaded rake, and the traversingof the entire intake. After the rake moves upward and clears the rack, the rake deposits the debrisin a hopper. The trash car is mounted on a set of rails and can move to a location where the carcan be lifted and dumped.

For heavy debris loading such as grass, seaweed and trees, several designs have been used. Oneis a heavy-duty clamshell-shaped rake and another is the traveling bar rack. The traveling barrack is similar to traveling screens with bar spacings of 0.5 to 1 inch (1.3 to 2.5 cm) between thewidely spaced racks and the screens. These designs are used to screen kelp and seaweed on thePacific coast plants.

At power plants in cold-weather climates, trash racks can become clogged by floating or frazilice in the water flow. Frazil ice is the initial crystal from which ice develops in water bodies. It isinitiated by supercooling of the water caused by low air temperatures and surface winds greaterthan 10 mph (16 kph). Frazil crystals form on the top stratum of flow and are easily mixed intothe lower strata by turbulence generated by winds and currents. These crystals can adhere tounderwater trash racks, reducing or blocking water passage. Warm water re-circulation, or theintroduction of steam upstream of the racks, can raise the inlet water temperature and preventfrazil ice formation. Air bubbler designs can also prevent frazil ice formation. Curtain wallsupstream of the racks and below the extreme low water level are the prevalent method of floating


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ice control at power plants. Floating ice booms are not very effective in preventing floating icesheets 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 5-3Typical 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 ofmetallic or plastic mesh through which the water must pass. The mesh is mechanically rotatedabove water for cleaning. The screen mesh is held rigid by multiple small trays or baskets linkedtogether to form a continuous belt. The belt revolves with the upstream side rising with itscollected debris to the structure deck where the screenwash system is located. At the deck, thescreenwash water system directs high-pressure sprays through the mesh to wash off debris intothe disposal trenches.

Most maintenance can be performed at the deck level without removing the screens from theguides. 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/filteringscreens 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 lastchance to catch debris before entering the waterbox. The capital cost for a debris filter can behigh and available space can present problems for a retrofit.

Filters increase circulating water system head loss and reduce circulating water flow rate. Theselosses can be overcome by increasing the circulating water pump horsepower. A picture of adebris filter is shown in Figure 5-4.


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Figure 5-4Debris Filter (courtesy of Taprogge)

5.2.2 Flow Reversal

Another means to supplement an effective screening system and to clean debris accumulation inthe condenser waterboxes and on the tubesheets is to backwash the condenser by periodicallyreversing the circulating water flow direction. The condenser backwash is achieved by providingadditional pipelines and valves around the condensers and by controlling the various valvepositions 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 coolingwater temperature to be raised above the thermal tolerance level of thefouling organism, for example, zebra mussels.


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Defouling of the intake structure and inlet water piping requires a flow reversal within thesystem 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 watertemperature, exposure duration, and frequency of backwash.

With the backwash is the inherently less efficient operation of the remaining condensers or heatexchangers. Total flow is reduced and/or inlet water temperature is raised above the expectednormal design level. Unit output will be reduced during the backwash cycle. This procedure canbe 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 andsubsequent growth of fouling mechanisms is termed hydraulic control. Thevelocity needed to prevent settlement of the fouling organisms is between 2and 4 ft/sec (37 and 73 meter/min) on smooth surfaces and 4 to 6 ft/sec (73 to110 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 shortperiod 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 ofthe larvae.

x Dead areas must be minimized. These areas include the inside of pipe bends, accesschambers, expansion joints, valves, pits, and corners of culvert piping. These areas are nearlyimpossible to avoid.

Given these factors, hydraulic control may have little practical application alone in solving themacrofouling at power plants. However, high velocity circulating water of 4 to 6 ft/sec (73 to110 meter/min) should be used whenever possible to inhibit macrofouling and reduce thefrequency of cleaning.

5.2.5 Materials Control

One approach for reducing or preventing macrofouling within the circulating water system is theuse of antifouling coatings. The advantage of this approach is that marine fouling is prevented atthe point of attachment, thus requiring only the intake and piping surfaces to be treated asopposed to the entire water volume.

Development of copper-nickel alloy metals has provided another means of fouling control. Thecopper-nickel metals possess antifouling properties and are used in the manufacture of pipingand 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 sheetingand plastic pellets.

Key Technical Point

Copper-nickel alloys form an adherent cuprous oxide corrosion film. Thecopper ion content in the film, when released into the cooling water, is toxicto marine biofouling organisms and inhibits their attachment to the metalsurface.

Fouling organisms can attach to copper-nickel alloys’ surfaces if the water velocity is less than 4ft/sec (1.2 m/sec). The average water velocity within a power plant circulating water system is 8ft/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 copperion 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 antifoulingproperties 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 areused as part of a total coating system that consists of an anticorrosion primer over steel or asealer 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, exfoliationor loss of paint surface can be caused by dynamic action with water, impact by floating debris, orabrasive contact with entrained solids, such as sand. This contact can mechanically remove thecoating 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. Amixture of hypochlorous acid and hydrochloric acid is formed when hypochlorite or chlorine gasis added to water. Sources of chlorine available to power plants include gaseous chlorine (storedas a liquid under pressure), calcium hypochlorite, liquid sodium hypochlorite, and onsitehypochlorite generation.

Key O&M Cost Point

Gaseous chlorine is frequently used by utilities because chlorine in this formis relatively low in cost. Unfortunately, chlorine gas is highly toxic. Sodiumhypochlorite, although less dangerous, is more expensive than liquidchlorine.

Onsite generation relieves transportation and storage problems associated with the other systemsbut 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 tocontrol macrofouling. Many environmental factors, such as predominant organisms, growthrates, location, season, and water temperature affect chlorine dosage and application rates.Intermittent chlorination is relatively ineffective against hard-shell foulants such as mussels andbarnacles. Continuous chlorination at low levels, at least during the growing season of themacrofoulants is required to effect complete control of mussels and barnacles. See Section5.4.4.1 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 chemicalbiocides 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 incontrolling biological population growth. Typically, this is performed in conjunction withchemical treatment of the intake water to kill the organisms.

Manual efforts to clean the condenser tubes and tubesheet to control macrofouling are commonlyused. These efforts are labor intensive and require load reductions or the unit off-line. The tubescan be cleaned and debris and deposits removed by brushes, scrapers, or rods. Section 6 dealswith 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 causedby chemical means, biological means, or both. Metal surfaces undergo chemical and biologicalchanges when immersed in natural waters.

Chemical interaction between the metal’s surface and water results in the deposition of inorganicions and the adsorption of dissolved organic substances. This process leads to the formation of aconditioning film, approximately 1.968 micro-inches (50 nanometers) in depth. The film enablesbacteria and diatoms to colonize. Those colonies produce an extracellular polymeric substancethat encourages further growth of the biofilm.

Interrupting biofilm growth will not necessarily solve heat transfer problems. For example, if theheat transfer surfaces continue to be covered with the dead biofilm and an extracellularpolymeric substance layer, heat transfer will remain impeded. In addition, if the biofilm growthcharacteristics are not taken into account, then insufficient cleanup of the biofilm can lead torapid 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 inthickness of the biofilm. This is shown in Figure 5-5.

Figure 5-5Typical 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 withconstant thickness

Any biofouling control method must move the system from Phase 3 or Phase 2 solidly back intoPhase 1. Because growth is explosive in Phase 2, cleaning that brings the system back only toPhase 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 inbiofilm development but they might change the rate of growth at different times.


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Phase 1: Lag or Induction — Pioneer bacteria cannot adhere to a surface such as the interior ofa condenser tube wall until organic molecules are transported from the bulk fluid such as coolingwater to the substratum. Some of the organic molecules adsorb, resulting in a conditionedsubstratum. These adherent materials also provide nutrients for microorganisms that becomelodged on the surface. Adsorption of an organic conditioning film is very rapid compared to theother biofilm processes.

The microorganisms that become attached to the wall come in three waves. Rod-shaped bacteriaare the first. These produce an environment conducive to attachment by other organisms.Bacteria of other shapes (stalked, budding, filamentous) follow. The third wave is othermicroorganisms such as protozoa and fungi. If protozoa are present in the cooling water and jointhe biofilm, they can reduce the accumulation of other organisms by feeding on them. Otherdebris, including the simple organic molecules needed for bacteria nutrition will continue toattach to the condenser tube walls during this wave.

Phase 2: Logarithmic growth — No serious thermal, friction, or corrosion problems wouldresult from the simple adhesion to metal surfaces of those few microorganisms present in thecooling water. However, those nutrients provided by the cooling water will allow the attachedmicroorganism to feed and multiply. Given sufficient nutrient availability and a favorablesurrounding temperature, bacteria can reproduce in 20 minutes to several hours. This exponentialgrowth 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 thecooling water stream. A steady state or plateau phase is reached in which growth is balanced bydetachment or sloughing caused by the shear stress of the flowing water.

Biofilm thickness is an important characteristic in analyzing biofilm processes because thicknessdetermines the diffusional distance that must be known in order to calculate fluid frictionalresistance and heat transfer resistance. Accurate measurement of biofilm thickness is difficult.The biofilm thickness can vary considerably over a given substratum due to irregularmorphological features of the biofilm. Variation in thickness can also be a function of biofilmage.

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 thicknessmeasurement. Biofilm mass densities have been reported as high as 6.55 lb./ft.³ (105 kg/m³) andas 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 depositsthat 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 arethe direct result of bacterial action, particularly in freshwater. The bacteria on the surface of thepipe 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 thebiofilm including surface conditions, water quality, fluid velocity, watertemperature, and tube alloy.

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

Figure 5-6Biofilm Development Factors

Each of these biofilm development factors is described below.

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

x Water Quality – Water quality considerations include the presence of microorganisms andnutrients and other factors such as salinity. The planktonic bacteria and other microorganismsin 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 ofthe 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 thewater. 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 coupledwith high flow rates. In addition to organic carbon, nitrogen, phosphorous, and phosphatesmust 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 notusually as available as dissolved nutrients. Suspended solids also scour the walls and increasethe 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 thedifficulty of removing it.

x Fluid Velocity – Fluid velocity can have either a positive or a negative effect on biofilmdevelopment. Adequate water flow brings organisms and nutrients to the condenser walls.High velocity also increases detachment. Steady state conditions are a balance betweennutrient loading and shear due to flow. Steady state biofilm mass is usually lower in highvelocity systems because detachment is increased. Most condensers, however, are designedfor operation at a specific maximum velocity. Therefore, velocity cannot be raised beyond acertain 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 easyto conclude that increased water temperature causes this increased growth. While bacterialmetabolism and growth increase in higher temperatures, the summer effect might also be dueto increased nutrients in the large volumes of cooling water. Many plants increase their totalcooling water flow through the summer. The increase in biofouling rate and extent due toincreased water temperature is significant when the organic carbon availability alsoincreases.

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. Forbiofouling, the materials rank as follows: copper nickel showing the slowest biofouling, thenbrass, then titanium, and stainless steel the fastest biofouling.

These results are not surprising because copper is toxic to bacteria. Although copper nickel andbrass slow biofouling, these materials might experience higher corrosion rates than the total heatrate degradation. This is because corrosion plus biofouling might actually be greater with thesealloys. Also, copper corrosion can release copper ions into the water, affecting the plant’s abilityto 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, thematerial is relatively unimportant.

5.3.2 Chemical Fouling

Chemical fouling is the formation of a chemical deposit with poor heat transfer properties on theinside 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 andoccurs when the solubility of the salts is exceeded. The most common deposit is calciumcarbonate and removal of this deposit might require special cleaning tools. The solubility limitfor this compound decreases with increasing water temperature. This causes deposition as inletcirculating water heats up in the condenser. Generally, the largest deposits are found at the outletend 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 willadhere to the tube wall. Particulate fouling occurs when small particles of matter attachthemselves to the tube wall. Generally, there must already be a substrate of deposit material towhich the particulates attach. The common substrate is bacterial slime. Once attached, thedeposit layer accumulates rapidly with a corresponding decrease in the thermal heat transfer. Thestandard cooling water tube velocities of approximately 7 ft/sec (2 m/sec) are often high enoughto remove new material at the same rate as it is deposited. An equilibrium condition is reachedwhen no further deterioration in performance occurs. This fouling process has been termedasymptotic fouling. Off-line cleaning methods are commonly used to remove particulate fouling.

Key Technical Point

Chemical additives used for biological control or corrosion inhibition canalso result in microfouling. For example, water containing manganese willreact with chlorine to form manganese dioxide particles and substantiallyincrease fouling risk. Copper alloys and 300 series stainless steels are likelyto suffer significant corrosion under these circumstances.

5.4 Microfouling Chemical Treatment [15]

Key Technical Point

Several factors must be considered when using chemicals to controlmicrofouling of main steam condenser cooling water systems. These factorsinclude condenser cooling system design and operation, biocontrol agents,environmental regulations, chemical application methods, and safety andexposure.

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 toa body of water without recycle or reuse. In recirculating cooling water systems, water passesthrough the condenser to a cooling tower or spray pond, where evaporation reduces thetemperature before the water recycles back to the condenser. Some water is discharged from thesystem 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 andamount of chemicals that can be discharged. A major advantage of recirculating systems is thatthe chemicals remain within the system continuously. This reduces the amounts needed forbiofouling control and reduces the quantities discharged for the system. Both types of systemshave chemical discharge limits but recirculating systems discharge a lower volume of chemicalsand water than once-through systems. Also, restricting the discharge of cooling systemblowdown for several hours to allow for reaction and decay of biocides can reduce chemicaldischarge levels substantially. Re-circulating systems, thus, have considerably more flexibility interms 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 orseveral biocides to all of the water passing through the condenser. Biocides are chemicals thatare toxic to organisms.


To be effective in controlling biofilm formation, all biocides requireadequate 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 organiccomponent of the microorganisms. This kills or deactivates the microorganisms. The mostcommonly 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 severalchemicals) and chlorine dioxide. Table 5-1 compares the most common oxidizing biocides.

Table 5-1Commonly Used Oxidizing Biocides [15]

Characteristic Chlorine-Based Bromine-Based Chlorine Dioxide

Application Methods Fed primarily as a gasor aqueous solution

Fed as aqueoussolution or generatedvia oxidant reactionwith bromide salt

Must be generated atthe site and mixedwith water

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

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

A residual of 0.05-0.1mg/liter for one hourper day (four times for15 minutes each)

Cost-Effectiveness Usually most cost-effective

Generally 50-100%more costly thanchlorine

Generally 700-800%more costly thanchlorine

5.4.2.2 Non-Oxidizing Biocides

Non-oxidizing biocides are systemic poisons that kill the microbiological organisms byinterfering 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 flushedfrom the tubes by the cooling water turbulence. There are many different non-oxidizing biocidesand mixtures in a single product. Some typical non-oxidizing biocides are complex fatty acidquaternary ammonium compounds (known as quats), organic halogen compounds (such as


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brominated proprionamide), sulfur-based products (such as thiocarbamates), and organicchemicals 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 ofcooling systems. Many non-oxidizing biocides are not used in once-through cooling systemsbecause of possible impact on the environment and discharge restrictions.


The biocide label lists restrictions that govern the use of the biocide for allapplications. It also lists danger signs, environmental hazards, treatmentmethods, storage and disposal instructions, and how to apply initial andsubsequent dosages.

Non-oxidizing biocides often maintain their activity even after discharge from the system, whileoxidizing biocides are usually consumed in minutes. Regulator limitations should be understoodbefore using non-oxidizing biocides.

Non-oxidizing biocides are usually liquids with several components: the active biocide orbiocides, solubilizers, dilutants, and occasionally surfactants or wetting agents. Most are water-based, although some are water dispersible slurries or in hydrocarbon solvents. All of thesechemicals are toxic and often quite hazardous to handle. Each product Material Safety DataSheet 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 5-2Typical 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 EnvironmentalProtection 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 astrong cationic charge that can react with commonly used anionic dispersants and/or scaleinhibitors, 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. Itis 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 iscorrosive to copper alloys.

Non-oxidizing biocides are used alone only when special conditions occur, such as when thecondenser cooling water consumes large quantities of oxidants (due to high iron and/ormanganese content, typical of mine drainage waters). However, such stand-alone non-oxidizinguse is very specialized, even when treated sewage plant effluent (with a high oxidant demand) isused for condenser cooling water. Most commonly, non-oxidizing biocides are used tosupplement 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 imperativeto know which class or classes of microorganisms can be controlled with each chemical. Plantengineers and chemists must be aware of the limits of adverse actions of these chemicals andbase the application of these chemicals on knowledge of their effectiveness at a specificconcentration 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 oxidantsinclude hydrogen peroxide and ozone. However, these oxidants have had limited application andmust be reviewed for site-specific application. In general, they are either too costly or havelimited 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 aliquid, usually as a 30% water solution. It is fed via a pump, similar to the sodium hypochloritesolution. It is a weaker oxidant than chlorine. Use levels are equivalent to chlorine, 0.5-1.0mg/liter active oxidant, but effectiveness usually requires a minimum of twice the contact time.


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After reaction, hydrogen peroxide is reduced to water and oxygen. Thus, from an environmentalstandpoint, this lack of regulated by-products is a major advantage. It is commonly used in high-purity systems for biocontrol.

Ozone

Ozone is currently being evaluated in small air-conditioning cooling systems. Ozone gas isproduced by passing dry air or oxygen through an electric current or corona. The gas is dissolvedin water and the solution is then injected into the cooling water. Dosages are usually less than 0.2ppm oxidant, because higher levels can oxidize (corrode) other materials in the system. Ozonehas very limited solubility in water, much like oxygen, and is easily stripped at the coolingtower. Ozone reacts quickly with many organics and biomass and it is quickly depleted. Ozone isoften completely consumed and not detectable 10 minutes after injection. Multiple injectionlocations might be required.

On the other hand, ozone decays to oxygen. The lack of residuals can be an environmentaladvantage. In general, ozone appears to not be cost-effective for utility plants, due to the highcost of generation and installation, rapid reaction, low solubility, and unpredictability ofperformance. However, studies continue to evaluate ozone for biofouling control. If it can alsohelp 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 ismeasured by the intensity of the lamp and the power input. However, it is active only as far asthe 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


The Environmental Protection Agency (EPA) and the states mandate threetypes of regulations governing the quality of discharges. They aretechnology-based regulations, historically based effluent water qualitystandards, 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), bestconventional technology (BCT), or best practicable technology (BPT). These limitations areeither parameter-specific, covering parameters such as pH and the total suspended solids, orchemical species-specific, covering species such as total residual chlorine and total copper.Monitoring requirements are usually satisfied by grab or composite sampling and analysis atweekly or monthly intervals. Some discharge permits require continuous monitoring of totalresidual chlorine as a condition for allowing continuous chlorination for macroinvertebratecontrol.


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Oxidizing biocides (chlorine, bromine, ozone, chlorine dioxide) are frequently regulated as agroup in parallel fashion. Non-oxidizing biocides are not commonly used for microbiofoulingcontrol in once-through cooling systems for reasons of cost and toxicity. Their use in recirculatedcooling systems is similarly limited, although to a lesser extent. In some recirculated systems, itmight be possible to discontinue blowdown for a sufficient length of time to permit degradationof the biocide to levels acceptable for discharge.

For chlorine best available technology, effluent limitations for once-through cooling water are0.2 mg/liter maximum total residual chlorine. Further total residual chlorine might not bedischarged from any single generating unit for more than two hours per day unless the generatordemonstrates to the permitting authority that a longer discharge period is required formacrofouling control.

The best conventional technology discharge limits for chlorination of once-through coolingsystems are specified in terms of free available chlorine concentration during application: 0.5mg/liter maximum free available chlorine and 0.2 mg/liter average free available chlorine. Nosingle unit can discharge chlorine for more than two hours per day. No more than one unit at aplant 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 thislevel of chlorination.

Both of these regulations are concerned with the chlorine content at the point of discharge fromthe plant. Usually free available chlorine is only a small fraction of total residual chlorine at thepoint of discharge. Therefore, the best available technology guidelines regulating total residualchlorine 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 aresummarized in Table 5-3.

Table 5-3Technology-Based Regulations for Chlorine [15]

Level ofControl

DischargeLimitations

Covers Time Limitationson Discharge

Exceptions toRegulations

Best AvailableTechnology

0.2 mg/litermaximum totalresidual chlorine

Once-throughcooling systemswith plantcapacity > 25Mw.

2 hours per day perunit; simultaneousmulti-unitchlorinationpermitted

Longer chlorinationperiod might beallowed ifmacrofouling controlis required

BestPracticableTechnology

0.5 mg/litermaximum; 0.2mg/liter averagefree availablechlorine

Once-throughcooling systems;recirculatedcooling systemblowdown

Two hours/day; oneunit at a time

Utility might be ableto demonstrate thatunits cannot operateat or below requiredlevel of chlorination


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In general, the technology-based regulations are species or compound-specific numerical limits, either concentration or mass per unit time. Theselimitations are based on the performance of the best available technology onthe particular category of effluent for a particular industry. Theselimitations 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 (forexample, chlorine or benzene) regional or statewide limits on the concentration of a dischargedchemical. They have a historical rather than a precise mathematical relation to stream quality.They represent an amalgam of technological, water quality, social, political, and economicconsiderations.

5.4.3.3 Receiving Water Quality-Based Standards

The receiving water quality-based standards are directly related to the water quality requirementsfor the receiving water body. They can be stated in terms of chemical specific concentration unitsobtained by a designated analytical methodology. For example, a limitation might be that coppermust 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 whole-effluent toxicity test conducted on the discharge.

Unlike the best available technology and best practicable technology limits that generally mustbe measured directly at the discharge point, the water quality-based limits generally considerreceiving water mixing characteristics. However, differences in acceptable dilution models canaffect the allowable discharge from power plants.

The criteria continuous concentration (CCC) and the criteria maximum concentration (CMC) fortotal residual chlorine that affects chlorine discharges are:

x CCC is the highest four-day average instream concentration of a toxicant that cannot beexceeded more frequently than once in three years. The concentration must also be at orbelow the concentration that organisms can be exposed to indefinitely without causing anunacceptable effect. The CCC for chlorine is 11 Pg/liter total residual chlorine in receivingfreshwater and 7.5 Pg/liter total residual chlorine in receiving saltwater outside of the mixingzone.

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


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The EPA establishes effluent guidelines and water quality criteria. Most state regulatory bodiesuse these guidelines and establish state water quality standards as a basis for issuing dischargepermits. 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 butare regulated under the water quality criteria set by the EPA, specific standards for all statescannot be listed here.

5.4.4 Chemical Application Methods

For condenser biofouling control, biocides are usually applied periodically. The duration of thebiocide 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 frequencymust be at the level that will maintain efficient condenser operation while meeting applicableregulations for biocide discharge.

The site-specific National Pollution Discharge Elimination System (NPDES) discharge limit isoften the limiting factor in choosing the optimum biofouling control procedures for a particularsite. However, a variance in procedure might be possible if the condensers are severely biofouledand/or the water supply is highly contaminated.


Oxidizing biocides are usually the primary biocontrol agents for once-through and recirculating condenser cooling water systems. Non-oxidizingbiocides seldom are used in once-through condenser cooling water systemsexcept for special applications such as macrofouling control.

In recirculating cooling water systems, particularly cooling towers, a slug addition on non-oxidizing biocides is common as an assist or booster to the oxidizing biocide. This is used tocontrol 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 weeklyor less often. If the non-oxidizing biocide is the primary biocontrol then application and dosagemight be greater. Because cooling tower systems recirculate and retain the cooling water, slugaddition provides extended contact time with the biocide.

Effectiveness of the biocide depends on its properties. These properties often are a function ofsystem water pH, hardness, turbidity, the type of microorganisms, and degradation of the biocidewithin the system. Depending on the biocide and its toxicity, a detoxification step might berequired 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 inpower plant applications for control of fouling by microorganisms. Another oxidant, chlorinedioxide, is a special and specific compound quite different from chlorine. The other predominant


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

5.4.4.1 Chlorine

Chlorine compounds typically are fed as aqueous solutions into the cooling water going to thecondenser. This can be done immediately before the condenser or at any convenient locationupstream 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 ofthe 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 90.7kg) cylinders or, for larger amounts, in railroad tank cars. When cylinders are used in the powerplant, several cylinders are often manifolded together to increase the time between cylinderchanges. The pressurized liquid chlorine, which is 100% available chlorine, vaporizes to gaswhen released to atmospheric pressure at temperatures above 40qF (4.4qC). At lowertemperatures, a heater is often used to obtain effective vaporization. Liquid chlorine can damagethe chlorine feed system by backing up into the chlorinator as a water/gas mixture when only adry gas is present.


Chlorine gas is very toxic and extremely irritating. It is a green vapor that isdenser than air. Small leaks can be detected with a 10% solution of ammoniahydroxide. The chlorine and ammonia vapors form a white vapor ofammonium chloride.

A typical chlorine gas feed schematic is shown in Figure 5-7.


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Figure 5-7Chlorine Gas Feed Schematic [15]

The chlorine gas passes through a flow meter, and then is thoroughly mixed with water in anaspirator or water jet eductor. The resultant solution is usually several hundred parts per millionof hypochlorous acid with some chlorine at a pH of 3 to 4. This concentrated hypochlorous acidsolution is then fed to the cooling system where it is diluted with the cooling water to aneffective biocidal concentration of a mixture of hypochlorous acid plus hypochlorite ion, withproportion depending on the final pH.

Clean water, free of suspended solids, should be used to prevent feeder plugging. Concentratedcooling tower water used in the eductor should be avoided because many treatment chemicalscan be totally degraded when contacted by the concentrated hypochlorous acid and low pHsolution 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 feedfor several days can result in rapid biomass buildup in the condenser.


Appropriate safety equipment such as chlorine gas masks should beavailable in case a leak occurs in feedlines or at cylinder connections.Consult the Material Safety Data Sheet and product label for specific safetyhandling and spill precautions.


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Sodium hypochlorite is the second most commonly used source of chlorine. It is found as analkaline water solution of sodium hypochlorite with several percent free caustic. This solution ismade 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% solutionwithin a few days. Sodium hypochlorite gradually emits chlorine regardless of altitude,especially at temperatures above 90qF (32qC). Lower concentration solutions of 5% and 8% aresometimes used for smaller systems. By comparison, household bleach is a sodium hypochloritesolution of approximately 5% available chlorine.

Sodium hypochlorite solutions are most often added to the cooling water via a corrosion resistantpump in an area of good mixing or through a mixing chamber. Due to the highly alkalinehypochlorite solution, calcium scale can develop when using or injecting into high hardnesswaters. As with chlorine gas, if cooling water is used for mixing, the high chlorine concentrationcan degrade some of the water treatment chemical effectiveness. Thus, it is advisable to usefreshwater for dilution to prevent this degradation.

Sodium hypochlorite is a strong oxidant and a highly alkaline (free caustic) liquid that will causeskin and eye damage. Organic or cloth rags should not be placed in contact with sodiumhypochlorite liquid. A rapid reaction (possible explosion) and/or spontaneous combustion canoccur.


Appropriate safety equipment such as facemask, eye goggles, rubber gloves,and apron should be worn when handling any equipment used to store orfeed sodium hypochlorite. Consult the Material Safety Data Sheet andproduct label for specific safety handling and spill precautions.

A variety of dry products release chlorine. These products are not normally used as the primarychlorine source for biofouling control because of high cost. They are generally used as temporaryor emergency substitutes when the regular supply of chlorine gas or sodium hypochlorite isexhausted 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 byreacting lime (calcium oxide) with chlorine. When added to water, the dry product dissolves andreleases both calcium and hypochlorite ions. It is added through a dry chemical feeding systemor by spreading the dry product into the cooling water.

Dry chlorine release chemicals are strong oxidants and any skin or eye contact can causeirritation or damage. The dust or powder is also very irritating to eyes, lungs, and skin.


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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 orfeed chlorine. A dust mask can also be used. Consult the Material SafetyData Sheet and product label for specific safety handling and spillprecautions.

Table 5-4 summarizes the main methods of adding various chlorine compounds.

Table 5-4Chlorine-Based Oxidizing Biocides [15]

Biocide ChemicalMakeup

Form ApplicationMethods

DeliveryMethods

ChemicalReactions

ChlorineGas

100%Chlorine

Liquid gasunderpressure

Mixed withwater and fedas aqueoussolution

Pressurized100,150, 200lb. (45, 68, 91kg) cylinders orrailroad tankcars

Vaporizes to gas;reacts with coolingwater to formhypochlorous acidand hypochlorite ion,proportiondepending on pH

SodiumHypochlorite

NaOCl, madeof chlorinegas andsodiumhydroxide,usually 10-12% activechlorine

Liquid Mixed withwater or fedas concentrate

55 gallon (208liter) drums,truck or railroadtank cars, ortote bins

Reacts with coolingwater to formhypochlorous acidand hypochlorite ion,proportiondepending on pH

CalciumHypochlorite

Ca(OCl)2,65% activechlorine

Dry: pellet,granular orpowderform

Broadcast intoan open flumeor coolingtower deck ormixed withwater and fedas an aqueoussolution

50 or 100 lb (23or 45 kg) drums

Reacts with coolingwater to formhypochlorous acidand hypochlorite ion,proportiondepending on pH

The targeted treatment technique was developed to maintain condenser biofouling control whilecomplying with very strict chlorine limits in the condenser cooling water discharge. Although thetargeted treatment technique can be used with a variety of chemicals, the usage to date has beenwith chlorine and is called targeted chlorination.

Targeted chlorination consists of initially making several penetrations in the condenser waterboxto install delivery piping. Software is available from EPRI to determine the appropriateconfigurations and number of pipes. The pipe delivers high levels of chlorine at 10-20 ppm at the


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nozzle that becomes diluted to 1-2 ppm at the condenser tubesheet. The chlorine treatment isapplied sequentially to a small portion of the condenser tubes (10% or fewer of the tubes in theentire condenser) in the inlet waterbox for a short period, such as five to ten minutes. Mixing anddiluting the discharge from these tubes with discharge from the other 90% untreated tubesassures compliance with environmental limits at the cooling system discharge.

The following designs have been tested at full scale: fixed piping, moving-manifold, andtubesheet manifold injection systems (each tube individually treated). The generic form of thismethod allows any water-soluble chemical, not just chlorine, to be injected in this manner. Thistechnique can offer an additional option to plants that have severe fouling but have stringentdischarge limitations. Corrosion and materials compatibility, however, is an important site- andchemical-specific issue that needs to be addressed before this method is employed. Currently, thefixed pipe design is in commercial use at several power plants. For more discussion on the EPRIproduct, see Section 5.6 of this guide.

5.4.4.2 Bromine

Bromine-based oxidizing biocides release bromine species into the cooling water. These speciesare hypobromous acid and/or hypobromite ions.

The pH of the cooling water determines the ratio in which bromine species are produced. ThepH-determined ratios are different for bromine and chlorine. At the typical pH levels found incondenser cooling water (6-9), bromine produces more of the acidic species than chlorine. Withbromine, 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 strongeroxidant and is a much more effective biocide than hypochlorite ion. The hypobromous andhypobromite 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 rangeof 7.5-8.5.

The bromine species have an advantage over the chlorine species in terms of reactions withammonia. Bromoamines formed in this reaction are much more active as biocides than theirchlorine equivalents and are almost as potent a biocide as the hypobromite ion. Thus, lowerlevels of bromine are being used for biofouling control. The bromine level used is often half theequivalent free available chlorine level used. This can partially offset the added expense ofbromine 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, verystrong oxidants, toxic and extremely irritating. They release bromine, which is a brown, heavygas 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-toxicliquids because they are generally water solutions of salts. However, as with any chemical,general precautions with handling should be observed. Dry bromine-release chemicals aresimilar to dry chlorine-release chemicals.


Fouling

5-32


Appropriate safety equipment such as facemask, eye goggles, rubber gloves,and apron should be worn when handling any equipment used to store orfeed bromine compounds. Consult the Material Safety Data Sheet andproduct label for specific safety handling and spill precautions.

Environmental regulations currently limit bromine species levels in plant discharge water to thesame levels as chlorine. These regulations are site-specific and are often expressed as limits intotal residual halogen or total residual oxidant, which includes both the bromine and chlorinespecies.

A variety of bromine or bromine-release chemicals have been used for utility condenserbiofouling 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 brominechloride 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 orsodium 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 coolingsystems where special conditions enable them to be cost-effective. Table 5-5 compares thevarious bromine compounds used for condenser biofouling control.

EP

RI

Lic

ense

d M

ater

ial

Fou

ling

5-33

Tab

le 5

-5B

rom

ine-

Bas

ed O

xid

izin

g B

ioci

des

an

d B

ioci

de

Pre

curs

ors

[15

]

Bio

cid

eC

hem

ical

Mak

eup

Fo

rmA

pp

licat

ion

Met

ho

ds

Del

iver

y M

eth

od

sC

hem

ical

Rea

ctio

ns

Bro

min

e Li

quid

100%

act

ive

brom

ine

Liqu

idT

hrou

gh fe

eder

sim

ilar

to c

hlor

ine

gas

feed

erP

ress

uriz

ed 2

000

lb.

(907

kg)

con

tain

ers

For

ms

hypo

brom

ous

acid

or

hypo

brom

ite io

n

Bro

min

eC

hlor

ide

Liqu

idB

rCl,

activ

ebr

omin

e/ac

tive

chlo

rine

com

poun

d; 5

5% a

ctiv

ebr

omin

e

Liqu

idA

s co

ncen

trat

edpr

oduc

t with

out

dilu

tion;

thro

ugh

diffu

ser

or d

ispe

rser

Pre

ssur

ized

200

0 lb

.(9

07 k

g) c

onta

iner

sR

eact

s in

wat

er to

form

hypo

brom

ous

and

hypo

chlo

rous

aci

ds

Bro

mo

chlo

rohy

dant

oins

1,1-

brom

o, c

hlor

o, 2

-di

met

hyl (

or m

ethy

leth

yl)

hyda

ntoi

n, 3

5-45

% a

ctiv

ebr

omin

e

Dry

: pe

llet,

gran

ular

, or

stic

k fo

rm

Com

bina

tion

stor

age

and

chem

ical

feed

er40

-lb. (

18 k

g) p

last

ic p

ails

to 1

500-

lb. (

680

kg)

tote

bins

Dis

solv

es in

wat

er to

form

hyp

obro

mou

s ac

idor

hyp

obro

mite

ion

Sod

ium

or

Cal

cium

Bro

mid

e

NaB

r or

Ca

Br 2

Dry

(10

0%)

or40

-45%

wat

erso

lutio

n

As

conc

entr

ated

prod

uct w

ithou

tdi

lutio

n;th

ru d

iffus

er o

rdi

sper

ser

Dry

: 10

0-lb

. (45

kg)

cont

aine

rs

Liqu

id:

55-g

al. (

208

liter

s)

For

ms

hypo

brom

ous

acid

or

hypo

brom

ite io

n


Fouling

5-34

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 brominecompounds, bromine liquid has the greatest concentration of the active ingredient (100%).However, a measure of cost-effectiveness must also consider handling, safety, feeding, andstorage.

5.4.4.3 Non-Oxidizing Biocides

Non-oxidizing biocides are most often applied either as a short (less than one hour) continuousfeed or a slug feed (added within a few minutes). These parameters are shown on the productlabel and are strictly regulated. Application is often made with a chemical pump to the coolingwater.

Common application dosages based on system capacity or water flow, range from 5 mg/liter to100 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. Thefrequency varies with the biocide and can be as often as every day or as rarely as once permonth, or irregularly, on an as-needed basis. Guidelines are provided by biocide suppliers andare printed on product labels. Some examples for various cooling systems are listed in Table 5-6.

Table 5-6Application of Non-Oxidizing Biocides [15]

Type of Cooling System Dosage Duration Frequency

Once-through 5 mg/liter based onthe flow of theproduct

15 minutescontinuousapplication

Daily

Recirculating 20 mg/liter based onsystem capacity

20 minutes withbiocide effective for12 hours

Once every twoweeks

Key O&M Cost Point

Most non-oxidizing biocide applications are much more expensive thanoxidizing 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-oxidizingbiocides require specific laboratory analysis procedures. Most techniques for monitoring non-oxidizing biocides focus on their effectiveness in keeping an acceptably low level ofmicroorganisms in the cooling water or maintaining the condenser free of biomass, not on thespecific chemical. Thus, monitoring condenser cleanliness is the primary emphasis. Toxicdischarge is also a criterion to be evaluated when using a non-oxidizing biocide.


Fouling

5-35


For non-oxidizing biocides, appropriate safety equipment such as facemask,eye goggles, rubber gloves, and apron should be worn when handling anyequipment used to store or feed the chemicals. Some of the non-oxidizingbiocides are extremely irritating. They can penetrate clothing, shoes, orleather and are rapidly absorbed through the skin. Some emit toxic irritatingvapors. Great care should be taken in handling all non-oxidizing biocides.Consult the Material Safety Data Sheet and product label for specific safetyhandling and spill precautions.


Biocides are regulated by the EPA. Each biocide must be registered for aspecific use such as microbiological control. In addition, it must be registeredfor the specific cooling water systems in which it can be used. The containerlabel must specify a variety of information, including at a minimum, thepercent of each active component, product use instructions, safety handlingprecautions, EPA registration number, and the EPA manufacturing locationnumber.

It is a federal violation to use a chemical in any manner other than its intended purpose or at anydosage/duration/frequency not specified on the label. Because all biocides are potentiallydangerous, it is important to have the safety, handling, and disposal procedures ready beforereceiving the chemicals. Personnel should be thoroughly trained to work with and handle thesesubstances safely. Biocide suppliers should provide the Occupational Safety and HealthAdministration (OSHA) and Material Safety Data Sheet (MSDS) forms before on-site delivery.Plant personnel should read, understand, and implement proper storage and handling precautionsbefore receiving the chemical. This information should be posted on the storage container andnear 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 condenserfouling. Using probes installed at one or more locations within a condenser, the condenserfouling monitor (CFM) provides more accurate heat transfer data than is provided by otherapproaches. The CFM uses one or more pairs of adjacent tubes in the operating condenser andextensions of those tubes mounted on the outlet tubesheet (see Figure 5-8). One tube in each pairremains open (active). The other (inactive) tube is plugged and used to measure inlet watertemperature and saturated steam temperature. Flow and temperature sensors are attached to anextension of the active tube, to measure outlet water temperature and flow velocity. Signals fromthe flow and temperature sensors are transmitted to a data acquisition system for storage andprocessing.


Fouling

5-36

Figure 5-8EPRI Fouling Monitor [16]

Using the measured flow rate, inlet and outlet water temperatures, and saturated steamtemperature, the system calculates the heat transfer coefficient. The CFM determines the extentof tube fouling by comparing the calculated heat transfer coefficient to the highest heat transfercoefficient achievable if the tube were in the same physical condition as that following the latestcleaning. 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 (0.6to 2 ppm) to selected areas (8 to 12 sections) of the condenser inlet tubesheet for short periods (5to 10 minutes). The solution is sequentially injected through fixed nozzles onto fractional areasof the tubesheet until the entire tubesheet has been chlorinated. This method effectively controlsbiofouling and dramatically reduces chlorine consumption up to 80 percent. The effectiveness ofbulk chlorination has been significantly reduced for once-through cooling systems since the EPAlowered the allowable discharge concentrations of chlorine residuals to 0.2 mg/liter total residualchlorine and restricted discharge to 2 hours/day per unit. The full-scale demonstration of thefixed-nozzle design at New England Power's Brayton Point Station Unit 2 Condenser showed thetechnology to be more effective at maintaining condenser cleanliness than the conventional bulkchlorination method.


6-1

6 CLEANING [15]

The primary objective of cleaning is to remove corrosion, fouling, and scaling material from theinner surface of the condenser tubes to bring heat transfer performance back to specification.

Key Technical Point

Some performance parameters that indicate condenser cleaning is neededare increased condenser backpressure, decreasing cleanliness factor,decrease in inlet and outlet cooling water temperature difference, heat rateincrease, and megawatt output decrease.

Recent chemical cleanings at two Exelon plants, Braidwood and LaSalle, resulted in significantimprovements in generating capacity. Braidwood Units 1 and 2 were cleaned with the chemicalFerroquest LP7202 with a gain of 5 and 7 megawatts, respectively, after the cleaning. Before andafter cleaning pictures are shown in Figures 6-1 and 6-2.

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


Cleaning [15]

6-2

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

Clinton Nuclear Station had calcium carbonate scale deposits in their condenser tubes. The tubeswere cleaned with cutters and scrapers and regained 20 Mw lost from the condenserperformance. 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 thecondenser performance. For more details on the Mw recovery of these units, see “ImprovedCondenser 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 onthe 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 andcage system, abrasive cleaning and self-aligning rockets. These systems canrequire a large capital investment. A continuous cleaning system offers theadvantage of keeping the tubes clean without any fouling buildup. Someadditional maintenance and operations attention is required. The constantscraping of the tube inside walls can cause tube thinning.


Cleaning [15]

6-3

Key Technical Point

The off-line cleaning techniques include the use of brushes, scrapers andhydroblasting. The equipment costs for these systems are relativelyinexpensive. 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 ascheduled load reduction. The cleaning process requires an operator and theair and water pressures used can impose a safety concern.

Each type of off-line cleaning system has limitations. Brushes are effective with the soft foulingdeposits. Metal scrapers and high-pressure water lances are more effective with harder scaledeposits. In some instances, it is necessary to chemically clean the tubes and then use mechanicaldevices 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 innersurfaces of the tube, removing material and possibly reducing wall thickness.

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

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 haveto 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 hazarddue 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 usedaggressively and/or incorrectly.

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


Cleaning [15]

6-4

The successful diagnosis and resolution of condenser performance problems related to fouling isbased on the identification of the fouling mechanisms and the corresponding effective cleaningtechnology. The effectiveness of the cleaning technology applied and the heat transfer loss fromthe deposits varies dramatically from site to site. Common investigative methods for foulingdetermination include the use of fouling monitors, sampling of the tube deposits, and single tubeheat transfer testing. The single tube heat transfer testing involves extracting a tube from thecondenser, measuring the heat transfer coefficient, cleaning the tube, and re-measuring the heattransfer coefficient. The results of this testing have been used to verify the condenserperformance testing, assist in locating the source of the performance loss, optimize the cleaningmethods, and monitor performance of cooling water chemical treatment methods. For moreinformation on these techniques, please see “Diagnostic Technique for the Assessment of TubeFouling Characteristics and Innovation of Cleaning Technology” [20].

No one technique for cleaning biofouling is ideal under all conditions. Sometimes chemicalcleaning is required to complement mechanical cleaning or vice versa. Chemical cleaning mightbe needed to reduce the fouling thickness followed by mechanical cleaning with scrapers orhigh-pressure water lances to remove the remaining fouling thickness. Chemical biocidetreatment might be needed to disinfect copper-alloy tubes from bacterial attack, supplementing aball cleaning or brush cleaning technique. Many utilities that use on-line ball cleaning also usebrushes or water lances during outages to remove debris or tenacious films on the tubes. Thesefilms 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 ballsthrough the condenser tubes. This action provides a continuous wiping action against the innertube walls. Figure 6-3 shows a typical ball cleaning system developed in Germany and modifiedby French, Japanese, and American companies.


Cleaning [15]

6-5

Figure 6-3Typical Ball Cleaning System [15]

This sponge ball cleaning system includes three steps: ball injection, tube cleaning, and ballcollection and return for re-injection.

Ball Injection — The balls are injected into the circulating water upstream of the condenserinlet, 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 areapproximately the same density as the cooling water. They should enter the tubes randomly sothat no section of tubes will be preferentially cleaned or neglected. A charge of balls equal to 5-15% of the number of condenser tubes per pass is sufficient to maintain cleanliness. With thisball count and continuous injection, each tube is expected to receive a cleaning ball about onceevery five to ten minutes.

Tube Cleaning — Experience shows that the actual physical distribution of balls might not beuniform. This can lead to inadequate cleaning or excessive wear of some tubes. This depends ontube material and cooling water conductivity. The ball distribution is affected by the location ofball 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 thenormal sponge rubber balls with balls that have an abrasive coating bonded to them. Granulaterubber balls have also been used to maintain the cleanliness of titanium tubes without scratchingthe tubes. When the foulant has been removed, normal service with plain sponge balls can


Cleaning [15]

6-6

resume. This practice must be monitored closely because of potentially rapid erosion of copper-alloy 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 inhigh-conductivity cooling water. Overcleaning tubes removes the protective film. Undercleaningmay leave a thick film that can inhibit heat transfer.

The erosion/corrosion of copper-alloy tubes and the action of ball cleaning might produce tracemetal effluents that affect water quality standards. Because of their inherent toxicity, copper-alloy 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 maintainoptimum cleanliness and tube service life. Under these conditions, one cleaning cycle per weekshould be sufficient. If the seawater is polluted or contains specific fouling agents that couldproduce pitting or other localized corrosion, the sponge ball cleaning frequency might have to beincreased to prevent under-deposit corrosion.

Ball Collection and Return for Re-injection — After the balls have traveled through thecondenser tubes, they must be caught without impeding the flow of water. They are caught by aspecially 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 cyclebegins 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 byagitation in the collector using the ball recirculation pump before release into circulation. Theseoperations are labor intensive requiring about two hours by one operator every week or twoweeks. Many users replace all balls without sizing based on an average ball lifetime determinedfrom experience. This reduces the labor required to operate the system.

The ball strainer can become clogged with debris or undersized balls. When the differentialpressure across the strainer becomes high, it is back-flushed into the cooling water dischargesection. The ball cleaning system is quite susceptible to the introduction of debris. If debris clogsor obstructs the tubesheet at the inlet waterbox, the tubes cannot receive cleaning balls. If debrislodges within a tube, there is a high probability that the tube will further plug with balls and/ormore debris. Ball system manufacturers and others supply a number of upstream debris filterdesigns that address this problem.

The debris filter systems can add significantly to the condenser capital cost. Because of theadditional pressure drop across the debris filter, the circulating pump motor power consumptioncan increase. This causes higher operating costs. The capital costs of the sponge ball system andthe increased maintenance costs must be compared to heat rate improvements from cleaner tubesand tubesheets.


Cleaning [15]

6-7

For existing systems, space and outlet piping configurations can influence the retrofit of a ballcleaning system. If debris affects the effectiveness of the ball system and a filter is required thenspace limitations at the inlet piping and in the condenser waterbox should be considered. Theoutlet piping affects the location, design, and cost of the ball collection strainer. All remainingsystem 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 ofball injectors required. A retrofit of the new designs is feasible except in difficult applicationswhere the inlet and outlet piping are embedded in concrete.

The greatest source of dissatisfaction among sponge ball cleaning system users has been the costassociated with system operation and maintenance. The piping systems, valves, and plugs canexperience accelerated corrosion. The linkages of the older designs become loose and theinstrumentation and controls require maintenance. Ball wear is a normal condition resulting inthe loss of under-size balls that pass through strainer catch screens. Full-size balls can lodgebehind debris or collection grids and become lost after a routine backwash operation. Ball hidingoccurs at stagnation points in waterboxes and other areas where low fluid velocity allows balls tostop moving. As the strainer section screen condition deteriorates, the balls are easily lost.


Ball replacement is a normal operating cost associated with proper systemoperation. The manufacturers normally recommend replacing a completecharge of balls approximately once a month because of ball wear. Historicaloperating data show that ball usage is often much higher. New designs mightbe an improvement in ball life.

Strainer design is crucial to successful operation. Over time, strainers become clogged withdebris, undersize balls, or ball fragments. A differential pressure measuring system can beinstalled on the strainer section to indicate debris loading and to initiate a screen backwashprocedure. This would occur if a predetermined differential pressure was reached. Some designsbackwash by canting the screens. Trapped debris is then flushed from the front side of the screenand out to the cooling water discharge destination. The strainer screens are then returned to theirnormal operating orientation.

The primary disadvantage of the older design multiple screen strainer is the large number ofmoving parts in the upper screens, lower screens, shut-off flaps, and throttle flaps. All of theseare 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 andmaintenance effort. The moving parts are actuated by both motor and mechanical operators. Theoperators require periodic maintenance and replacement. Figure 6-4 shows the older designstrainer system.


Cleaning [15]

6-8

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

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


Cleaning [15]

6-9

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

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


Cleaning [15]

6-10

Figure 6-6Sponge Ball Recirculation System [15]

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


Cleaning [15]

6-11

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, andball 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 causeproblems.

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 bysome large power plants, smaller power plants, cogeneration plants, industrial heat exchangersand refrigeration chillers. A typical arrangement is shown schematically in Figure 6-7. In thisarrangement, a captive brush is shuttled back and forth through each condenser tube by reversingthe direction of flow through the condenser. Flow reversal requires appropriate valves andpiping.


Cleaning [15]

6-12

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

There are several ways to install this flow-reversal mechanism. The type of flow diverters useddepends on the site piping configuration. There is no need for a strainer; the cleaning brushes arecaught by nylon cages attached to each tube end with epoxy or screws. The epoxied cages breakoff easily but are easy to repair. Flow reversal is usually initiated automatically on a timed cyclebut remote manual operation is also possible from the system control panel.

The brush and cage system requires limited maintenance or operator attendance. Other than theflow-reversal valves and the brushes, there are no moving parts. The brushes are usuallyguaranteed for five years. For a typical large power plant condenser it is recommended thatapproximately 500 spare brushes and cages be purchased to replace units that might fall off thetube ends. Large debris in the waterboxes can result in loss of brushes and serious damage to thecages. Figure 6-8 shows a typical arrangement for the brush and cage.


Cleaning [15]

6-13

Figure 6-8Typical 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 needfor 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 forbackwashing

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


Cleaning [15]

6-14

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 tubecleaner recovery system. The tube cleaner rockets consist of a two-part construction. The body ismade of hard wear-resistant material that provides long life. The cleaning element, anelastometric disk, determines the level of cleaning and can be made of abrasive material, ifrequired. The self-aligning design of the body helps with passage through the tubes. The rocketscan be hydraulically injected into the suction of the circulating water pumps (Figure 6-10). Thisensures even distribution throughout the volume of the cooling water.

The recovery system simply consists of modified oil spill recovery booms, a tube cleanerrecovery unit, and a means to recirculate the recovered cleaners. In most cases, the cleaners canbe 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 skimmingbooms channel the cleaners to a common collection point for recovery. The recovery is apontoon-mounted traveling screen. It retrieves the cleaners, rejects the floating debris, andcarries the cleaners to shore for inspection and re-injection.

Figure 6-9Tube Cleaning Rocket [4]


Cleaning [15]

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Figure 6-10Tube 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 nameSidtec 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 partialoutage of the condenser. Typical off-line cleaning methods and their effectiveness are outlined inTable 6-1.

Table 6-1Typical Off-Line Cleaning Methods and Their Effectiveness

Off-Line Cleaning Methods

Type of Fouling Brushes Scrapers Hydro-Blasting ChemicalCleaning

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 cleaningtime required.


Cleaning [15]

6-16

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 presentedin Appendix B. In addition, a confined space permit might be required when working in thewaterbox.

6.2.1 Air/Water-Driven Systems

One of the simplest off-line tube cleaning methods uses a bristle brush quite similar to (but withdenser bristles than) the brush used in the on-line tube cleaning system. The cleaning brush isinserted 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 thepropelling 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 conditionswarrant. Another method is simply shooting 200-400 psi (1.38-2.76 megapascals) of air and/orwater through the tube. This is the fastest method but is not appropriate for most cleaning.

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

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


Cleaning [15]

6-17

If the foulant is too hard to be removed by bristle brushes, then scrapers can be used. These aredriven with 200-400 psi (1.38-2.76 megapascals) of water pressure. Scraping edges should bespring-loaded to match the specified tube diameter.

There are two types of scrapers—plastic and metal. A picture of a plastic scraper is shown inFigure 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 scrapingedges are spring-loaded to press against the tube surface. The scrapers are propelled by water.

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


Cleaning [15]

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


Cleaning [15]

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Scrapers are one of the most effective off-line tube-cleaning methods developed. Because theyare 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 thescrapers are not left in the tubes. Scrapers left in the tubes might promote subsequent tube failureby 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 availablein a variety of configurations. Most are equipped with flexible shafts or universal joint shafts andare motor-driven. Some are adjustable to accommodate varying tube bores. An example of amotor-driven scraper is shown in Figure 6-15.

Figure 6-15Mechanically Driven Brush [15]

6.2.3 Pressure-Driven Systems

In water lancing, the foulant is removed by shearing the layers with high-pressure, high-velocitywater jets. Water pressures of 8,000-10,000 psi (55 to 69 megapascals) are normally used andpressures as high as 18,000 psi (124 megapascal) can be used. Operators need to take extremesafety precautions. These high pressures can collapse tube ends, collapse tube inserts, damagetubesheet 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 astainless steel head. The head is drilled with several orifices to define a particular spray patternthat will usually provide self-propulsion as well as tube wall cleaning. Lance head design iscritical to foulant removal. Typical water lance heads are shown in Figure 6-16.

Figure 6-16Typical Water Lance Heads [15]


Cleaning [15]

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This technique, also called hydrolancing or hydrolasing, uses a high-pressure water spray toremove fouling deposits. Water is pumped through a flexible hose or a rigid metal shaft fittedwith a steel spray head at the end. The head is designed for the spray pattern to impinge on thetubes 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-pressurewater can damage weakened tubes, the condenser should always be leak-tested afterhydroblasting. A hydrostatic testing (filling the condenser hotwell with water) should besufficient.

6.2.4 Waste Disposal

Dry off-line processes require an industrial vacuum cleaner with a filter to collect removeddeposits and limit airborne dust. Tarps or plastic wraps can also minimize airborne dust.

When cleaning closed cooling water systems, wet processes might require containment, testingand disposal of debris-laden water. Temporary traps or temporary rigid plastic channel coverscan contain water locally. Using detaining drums and/or temporary screens can limit thedischarge 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 outletwaterbox. 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 cleaningsystems require no maintenance or monitoring as compared to on-line equipment. There are noballs to replace, no back-flushes to initiate, nor any reverse-flow system transients. When the off-line cleaning is completed and the unit is back in service, the cleaning components are stored andrequire no attention.

A principal disadvantage of off-line tube cleaning equipment is that it interrupts service. Thecondenser 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/boileroutages or during scheduled load reductions.

On-line and off-line tube cleaning systems share the objective of maintaining tube cleanlinessand ensuring intended heat transfer rates. Tube cleanliness is maintained continuously by on-linesystems. Tube cleanliness might begin to deteriorate soon after an off-line tube cleaning iscompleted. If this situation can be tolerated because of very conservative design margins, thenoff-line systems can be sufficient.


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To prevent this, a conscientious program of off-line tube cleaning once or twice per year atscheduled 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 brushesdriven by relatively safe water pressures of 200-400 psi (1.4-2.8 megapascals) is the mostcommon 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 tenaciousdeposit, but they might need help where fouling buildup has been allowed to get too thick andhard.


When high-pressure water lancing equipment must be used, it presents apotential safety hazard to operating personnel because of pressures as highas 8000-10,000 psi (55-69 megapascals). Often this equipment is used by acontractor who specializes in high-pressure equipment. Propelling thecleaning devices through the tubes with high-pressure air or air/water alsopresents 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 slowto use for routine surface condenser tube cleaning. These methods are used where seriousproblems exist in the tubes and other off-line methods are unsuccessful. They can easily damagetube walls if they are used incorrectly.

All off-line tube cleaning methods use consumable cleaning devices that wear out and requireperiodic 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, andplastic pigs are:

x The equipment must be out-of-service with lost revenues from downtime or must bescheduled 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.


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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 condensermaterials. Typically, a removed tube and/or corrosion coupon is used in bench tests to verifysolvent compatibility with the condenser materials. Pulling tubes can be used for processoptimization. Visual inspections and eddy current measurements are used before and aftercleaning to evaluate cleaning effectiveness.

Both on-line and off-line chemical cleanings have been performed in the industry. On-linecleanings can be as simple as injection of the cleaner into a closed cooling water cycle. Off-linechemical cleaning involves the use of temporary equipment for chemical injection, condenserwater recirculation and vapor removal. The type of chemical cleaning selected for a specificplant (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 toone waterbox at a time or to the entire condenser. The off-line techniquesapply to the entire condenser. Chemical cleaning of the condenser typicallyregains lost megawatts.


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7 AIR/WATER IN-LEAKAGE

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

7.1 Air In-Leakage Effects [3]

For maximum thermal efficiency, corresponding to a minimum backpressure, a vacuum ismaintained in the condenser. This vacuum encourages air in-leakage. To keep the concentrationof non-condensable gases as low as possible, the condenser system must be leak tight, togetherwith any part of the condensate system that is under vacuum. Failure to prevent or remove thenon-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 levelsbelow 7 parts per billion (ppb) at full load and maintain non-condensable in-leakage to less than6.0 standard cubic feet per minute (scfm) (10.2 cubic meter/hr.). Achieving and maintainingthese 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 systemthrough labyrinth glands, penetrations, or other small apertures in those parts of the system thatoperate below atmospheric pressure. This air ingress cannot be avoided and the design valueused for the condenser tube side heat transfer coefficient reflects this value. When the air in-leakage rises above the threshold value, the tube side heat transfer can be affected and anincrease in the condensate dissolved oxygen concentration might occur. Of course, the lattermight not occur if the increased concentration of non-condensables consists of ammonia orcarbon dioxide as decomposition products from feedwater treatment chemicals.

The 1998 ASME Performance Test Code for Steam Surface Condensers Standard includes dataregarding 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 limitallows unaffected condenser performance. For a two condenser shell, 500 Mw unit with a totalexhaust flow rate of 2,300,000 lb/hr (1,043,262 kg/hr) the upper gas load limit from the chart is7.5 scfm (12.7 cubic meter/hr).

Westinghouse proposed a residual air in-leakage of one scfm (1.7 cubic meter/hr) per 100megawatts as being acceptable in their Operation and Maintenance Memo No. 029 in 1982. Thisshould again be considered in terms of an upper acceptable limit that will not affect condenserperformance. 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


Air/Water In-Leakage

7-2

criteria are clearly important when considering whether excessive air in-leakage is affectingperformance.

Table 7-1Air In-Leakage Limits(reprinted by courtesy of The American Society of Mechanical Engineers)

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

Number ofCondenserShells Between And

Non-CondensableGas Load Limit inscfm (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 amore severe effect on dissolved oxygen concentration than if it is transported to the condenserwith 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 Reduction in heat transfer coefficient – The condensing tubes are usually arranged in somevariation of a hexagonal pattern. The lower tubes have more air and the air does notcondense. The air can inhibit the condensation of the steam by creating a low-density blanketat the tube surface. The air acts as an insulator to condensation heat transfer. This results in areduction of the heat transfer coefficient h.



7-3

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 whendesigned to account for excessive air in-leakage.

x Excess process steam required for steam jet air ejectors – Diligent efforts can take place toreduce the amount of condenser air in-leakage where only one steam jet air ejector isnecessary. The cost associated with running two steam jet air ejectors can be approximatedby calculating the amount of steam required. An equation to calculate the normal amount ofsteam 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 effectivevolume of air at these design conditions is 606 cubic feet (17.1 cubic meter). The work requiredto remove one pound (454 grams) of dry air is 318 x 606 or 192,708 ft-lb/hr (261,273 J/hr or 73watts). 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)



7-4

To calculate the cost saved by a reduction in air in-leakage, first calculate the energy savingsthen multiply by the energy cost. The energy saving is the volumetric flow rate, multiplied by thedensity of air multiplied by the work rate of air.

(Energy/hr) = Volume/hr x density of air x work rate of air (eq. 7-4)

x Excess electrical load when another vacuum pump is required – In plants where the airremoval is obtained with mechanical vacuum pumps, it is necessary at times to use twopumps. 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 theplant capacity factor, hours in service, and the cost.

Cost/yr = Energy/hr x Capacity Factor ÷ motor/pump efficiencyx 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/pumpefficiency, 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 lossfrom 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 fromair 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 thecondensate/feedwater can cause problems in other areas of the system. Both titanium andstainless steel are relatively inert and tubes manufactured from these materials do not contributesignificantly to the chemistry of the system.

The carbon steel condenser shell will contribute ferric oxide to the system but the contribution isusually very small during power operation. During initial startup following a plant shutdown,reaction with ferric oxide will result in higher than normal hydrazine consumption. Relativelylarge quantities of scale and oxides will also be released during the startup period.

The consequences of excessive concentrations of dissolved oxygen (DO) in the condensatedrawn from the condenser vary. This depends on whether the unit is provided with a fossil-firedboiler or nuclear steam generator. Also, it depends on whether the latter is designed as a boilingwater reactor (BWR) or a pressurized water reactor (PWR). Because of the different



7-5

consequences, each type of plant has its own threshold for condensate dissolved oxygenconcentration that should not be exceeded.

With normal amounts of air ingress, the DO concentration should lie below the selectedthreshold. However, any air ingress into the condenser shell will create the potential for higherdissolved 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 varieswith 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 onthe effects in the PWR, BWR, and Fossil systems, refer to chapter eight of EPRI reportTR-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 thevapor 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 freesurface 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 fallthrough 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 tubebundle, or in steam lanes in the tube bundle, to the lower part of the condenser. The steam isdirected to the bottom of the condenser and hotwell area. In this way, a substantial amount of itsvelocity energy is converted to pressure energy. The local static pressure in the hotwell area andunder the tube bundles might actually exceed the static pressure at the condenser inlet. Thecondensate falling from the tube bundle through this zone of increased static pressure can beheated 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 steamflow paths around the tube bundle and through the steam lane in the tube bundle are fixeddimensionally. They are sized for steam flows in the higher power ranges. Full reheating of thecondensate is not achieved at the lower power ranges. This causes the dissolved oxygen levels torise. Some condensers incorporate a system to admit steam into this deaeration zone in order toachieve 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 byextraction steam from an appropriate source. The nozzles spray up toward the tube nest and are



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arranged in a manner to distribute steam near the cooling water inlet region. The steam suppliedby the nozzles offsets the subcooling, augments the normal steam upflow, and is regulated toensure that the condenser pressure does not exceed the design value. The sparging systemfunctions mostly during reduced power operation and startup.

There is an approximate linear relationship between sparging steam flow requirements andaverage 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 traysthat reduce the condensate water droplet size or film thickness. This facilitates the release ofdissolved non-condensable gases. Such an arrangement is applying the principles used indeaerating heaters for the purpose of reducing condensate oxygen levels. More space is neededbetween 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 theexception 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 hotwellwater and subsequent deaeration is the objective. It relies on the hydraulic motion of the bubblesto break up the water, which is already near the saturation temperature, and so release thedissolved 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 toperform a similar function.

7.1.3.3 Condenser Drains

The low-pressure drains are another major source of air ingress into the condenser. Airin-leakage into the vacuum regions of the turbine, the extraction system, and low-pressure heatershells becomes dissolved in the condensate drain water. Effective deaeration of the drain waterdepends 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 tobe inefficient or nonexistent. To ensure efficient deaeration, drain water flow should be dispersedin relatively thin films that pass through or are in contact with counterflow steam before itreaches the hotwell.

One way to accomplish more efficient drain water deaeration is to introduce the drain water intothe condenser above appropriate regions of the tube nest and to distribute the inflowing waterover perforated plates. This method facilitates contact between the drain water and upflowingsteam. Spray devices provide better conditions for deaeration than perforated plates. Specificperforated plate designs have to be provided for each condenser configuration. However, it isestimated that two 3 x 5 feet (0.9 x 1.5 m) perforated plates with 1/4-inch (6.4 mm) diameterholes in each shell provide reasonable distribution in a condenser of an 1100 Mw plant.



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7.1.3.4 Makeup Water

The makeup water is another important source of oxygen ingress. In many plants, the condensatestorage water is not deaerated. Because the water temperature is usually below the saturationtemperature, its dissolved oxygen content is high. Where the makeup water oxygen levelapproaches the equilibrium value of 10 ppm for aerated water at ambient temperatures, the effecton the condensate oxygen levels is pronounced. This assumes there has been little deaeration ofthe makeup water as it flows into the condenser. Plant makeup water flow rates vary widely butare generally in the range of 0.1% to 1.0 % (20 to 300 gpm or 76 to 1136 liters/min) of the ratedfeedwater flow. Preheating of makeup water would assist in deaeration. However, in existingcondensers, rearrangement of the internal spray piping might be necessary to avoid damage tothe condenser.

The design considerations for reducing the effect of makeup water oxygen content are similar tothose for drain flows. They involve introducing the water through sprays mounted high in theshell, preferably above the tube nest, and dispersing it in a manner that will provide good contactwith the steam. The high pressures available and the relatively small quantities for normalmakeup requirements favor the use of spray nozzles. Such nozzles, located in the tube nestregion, are used for normal makeup in a number of PWR plants. Consideration should be givento introducing the normal makeup water, via spray nozzles, above the tube nest. Delivery ofnormal 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



7-8

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 gasis the most commonly used method. Another method is to use a sensor probe to measure theamount of air leaking into the condenser. Infrared technology can also be used to find areas of in-leakage.

7.2.1 Tracer Gas Testing [22]

Gas tracer leak detection of any sealed container requires that a pressure differential existbetween the interior and exterior of the component being tested. The tracer gas is placed in thearea of higher pressure and migrates through leakage paths to the lower pressure area. Whentesting surface condensers, the gas is systematically sprayed over the exterior of the condenserand components that are a part of the vacuum boundary. The off-gas exhaust stream is thenanalyzed for the presence of the tracer gas. Leak detection using a gas tracer is a widely acceptedtechnique of identification of condenser leakage. Optimum conditions for gaseous tracer leakdetection 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 isinstalled in the non-condensable off-gas exhaust stream. A tracer gas is released in proximity ofsuspected condenser leak paths. Leakage is identified when the tracer gas migrates through theleak into the condenser. The tracer gas is expelled from the condenser steam space with the othernon-condensables in the off-gas. A small portion of the off-gas mix is drawn into the probe andto the detection system. The system analyzes the concentration of the tracer gas and reads onto adisplay. A technician monitors the display and relates the results to the technician disbursing thetracer gas.

Several different tracer gases including halogens (freon, sulfur hexafluoride), helium, andperfluorcarbons have been investigated. Helium is typically used and readily dissipates. Sulfurhexafluoride (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 bereleased 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 extremelyportable, has an extended operating duration, and has a variable release concentration to allowfor sensitivity adjustment.

The possibility of contamination of plant components and the potential for contaminating thefeedwater are minimal using the SF6 tracer gas. The low concentrations of SF6 gas necessary fordetection, the low solubility of SF6 gas in water, and the high efficiency of air-removal systemson non-condensable gases reduce the probability of measurable amounts of tracer gas carryingover into the condenser.



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In the plant environment, multiple leakage paths can exist in close proximity. A method must beemployed to isolate a specific leak from neighboring leaks. This can be accomplished byreleasing 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 thebackground signal. The process is then repeated for the remaining components.

Signal interpretation of indications for components in close proximity requires evaluation of thesignal magnitude, signal response time, signal slope, and signal clear-out. See Figure 7-1 for anexample indication of a leak. Signals with large magnitudes and quick response times usuallyindicate multiple leaks in close proximity.

Figure 7-1Chart 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 beexplained, but it must be practiced to achieve competency. At its simplest level, a tracer gas isreleased during the leak search and a signal is displayed when the gas is detected. There aretechniques in the gas release and signal interpretation that require experience and carefulattention to detail.

In a laboratory setting, it is possible to test and segregate one component at a time. A leak or no-leak determination can be made from the presence or absence of a signal. In the plantenvironment, multiple leakage paths can exist in close proximity. This requires that a method beused to isolate a specific leak from neighboring leaks. Also, the user must recognize signalscaused by the gas cross-over that occur while testing components near the leak.



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

A. Turbine shaft and labyrinth seal

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

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 7-2Turbine Shaft Gland Seal Housing [3]

In a typical air in-leakage test, tracer gas is released in the gland seal housing area in a six-second burst to determine if any of the paths are leaking. If the tracer gas is detected, the processof 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 ata time. This is done by releasing gas at the outermost items first and directing the gas awayfrom 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. Aquick burst, three seconds or less, is all that is required. With the release, a verbal On



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

x The time between gas release and the signal response (response time) is noted by the detectoroperator. When hearing the On message, the technician taps the event marker switch on thestrip chart recorder. This measures the elapsed time between the message and the first sign ofa signal response.

x Signal characteristics such as peak magnitude, rate of rise of the signal (slope), elapsed timefor the signal clear-out, and peak width are all significant.

The operator observes the incoming signal and records the peak value (magnitude) of theindication, together with the name of the item shot, paying attention to the slope traced by thesignal rise. Upon clear-out of the gas, the signal indication returns to background. Thisprocess 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 sulfurhexafluoride, 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 digitalreadout device that provides the controls necessary to establish sampling conditions and toindicate the presence of SF6 in the sampled off-gas (Figure 7-3).

Figure 7-3Gas Analyzer [3]

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



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

Figure 7-4Tracer Gas Release Device [3]

The concentration of the discharge mixture, nominally 1,000 ppm, can be controlled by adjustingthe delivery pressure on the regulator. The ability to vary the discharge concentration allows theoperator to decrease the concentration if background levels begin to rise. However, if thebackground level remains steadily low, the SF6 concentration can be increased for difficult areassuch as leakage below the condenser hotwell water line. A three-section telescoping aluminumprobe allows the tracer mixture to be directed accurately over the suspected leakage areas. It alsoenables the operator to reach areas that are difficult to access. Two switches control the releaseof the tracer. One controls the dilution air fan and the second opens the solenoid-controlledvalve, discharging the pure SF6 into the dilution stream.

The purpose of the sampling equipment, shown in Figure 7-5, is to draw a representative samplefrom the condenser air-removal system, to cool and dry it, and then to transport it to the analyzer.



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

Because moisture will significantly affect the operation of the analyzer, complete removal ofmoisture from the sample gas is desirable. When using a pump to draw an off-gas sample fromthe air-removal system, it is important to confirm that air is not leaking into the sampling systemon the vacuum side of the pump. Air leaking into the system will reduce the concentration of thetracer 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 byreleasing diluted tracer on those connections between the sampling system components that lieupstream 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 considerationbe 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 mightstand out above the others. If one of the signals has a magnitude that is substantially greaterthan 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 theshorter 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 andresponse times of two or more shots are equal, a steeper slope of rise (that is, a shorterelapsed time between the onset of the signal and the signal peak) will indicate which shot isthe leak or the more significant leak if several leaks exist.

4. Alternatively, if differences are still indiscernible, observing the clear-out times (elapsed timefrom the signal peak to a return to background) for each indication can be helpful. Forindications of equal magnitude, a faster clear-out would imply the shot location is closer tothe leak.

Although application of these last two tests might sound difficult, they can be performedquite easily. The strip chart can be displayed in such a way that all of the signals for theassembly can be seen and, if magnitudes and responses are equal, the signal with thenarrowest 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, fromtests associated with non-adjacent items, both having large magnitudes and quick responsetimes, 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 onhand, training of the staff, plant conditions, and time available.

Based on their experience, one contractor in the industry has created the following guideline todetermine which tracer gas to use:



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

x Dissolved oxygen — Due to its negligible solubility in water, it is recommended that SF6 beused as the tracer gas to search for the cause of DO leakage below the steam space. This doesnot 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 beused. If the unit has no power, it is recommended that helium be used due to its lowersensitivity than SF6. This does not preclude the use of SF6 but, when used, care should betaken to ensure that the SF6 dilution rate is increased to bring the sensitivity levels down tothat 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 bedeveloped. The checklist should start with a walkdown of the unit. Flow diagrams should bereviewed for inspection boundaries. Operating personnel should be consulted to confirmvacuum-boundary locations. The walkdown should start on the turbine deck and proceed to eachfloor elevation below the turbine deck.


The unit air in-leakage survey should start on the turbine deck at one end ofthe unit, continue around the turbines, include any other components on thedeck applicable to the test, and then proceed in a similar manner with thenext deck down. Regardless of the type of gas used for testing, the test shouldbe performed from the top of the unit to the bottom of the unit, one floor at atime. By performing the test first on the upper elevations, the tracer gasdrifting 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 wallstend 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 componentsclosest to and highest up on the condenser unit. For example on the mezzanine floor, the gasreleases should begin on one end of the unit by the expansion joint and progress down the slopeof the condenser neck, testing the various penetrations. After this area is complete, testing canproceed outward from that end of the condenser to testing penetrations on feedwater heaters, andso on.

By adhering to this order of testing, confusion is avoided when gas released at components outand away from the condenser is swept toward the condenser and drawn into leaks on the shell.



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After all components at one end of the condenser have been tested, the technician can movearound 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 giveindications 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 increasingmagnitudes of the section signal will indicate the direction of the leak. The presence of a largeleak might override or mask the signal of smaller leaks in the area, requiring a repair before leaksearching can continue in the area.

In order to isolate a leak, it is important for the technician to know what has been tested. This iswhy it is important to keep a log of everything that is sprayed with the tracer gas. If a large leakis found on the manway on the west side of the turbine, an indication of this must be made on thestrip 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 typicalresponse time originally recorded during the test shot.

Following these suggestions and performing an orderly, systematic, and detailed search patternwill greatly assist leak detection personnel in the successful application of the gaseous leakdetection technique.

To attempt to quantify every leak might not be cost-effective. However, there are variousmethods to determine the relative size of existing leakage paths. SF6 and helium analyzers givereadouts, one in millivolts, the other in divisions. Plant personnel can determine a plan of actionto 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 testshould be included in the test procedure. This section details the method for compiling achecklist. A well-constructed air in-leakage checklist will:

x Ensure that all components that might contribute to condenser air in-leakage are inspectedduring the test

x Facilitate testing by detailing the equipment in the order in which the testing will beperformed

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 theunit and a test technician should perform a review of the drawings and flow diagrams to establishthe inspection boundaries. This then serves as the basis for a walkdown of the unit, during whichthe systems and components that require testing for leaks are itemized.



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

I. Turbine Deck

A. Low-pressure turbines1. Gland seals and housing flanges2. Turbine case flanges3. Rupture disks4. Manways5. Steam cross-over lines

a. Expansion jointsb. Turbine penetrations

6. Turbine penetrations under the turbine skirta. Hood spray penetrationsb. Sensor penetrationsc. Miscellaneous valves, lines, and so on

B. Moisture separator reheaters1. Vent and drain lines routed to the condenser

C. 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 flanges1. Inboard seal2. Outboard seal

b. Turbine case flangesc. Rupture disksd. Steam stop valve drains and case penetrationse. Exhaust duct isolation valvef. Exhaust duct expansion joints

II. Mezzanine Level

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

A. Turbine to condenser expansion jointsB. Steam bypass lines and penetrations



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C. Air-removal lines1. Line penetrations2. Isolation valves3. Condenser vacuum breakers

D. Feedwater heaters1. Condenser neck mounted

a. Penetration expansion joints2. Floor mounted

a. Extraction steam lines1. Stainless steel expansion joints2. Weld joints

b. Heater shell penetrationsc. Relief valvesd. Drains

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

E. Condenser manways and penetrationsF. Upper sections of condenser waterbox tubesheet flangesG. Main steam stop-valve drains

1. Before seat drains2. After seat drains

H. Heater drain tanks (Flash tanks)1. All penetrations and lines

I. Seal steam condensers1. 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 dumps2. Condensate makeup lines3. Drain headers

B. Waterbox tube sheet flangesC. Hotwell penetrations

1. Sightglasses2. Level transmitters3. Condensate lines

D. Condenser supportsE. Heater drain pumpsF. Condensate pumps

1. Pump suction strainer housinga. Pump suction strainer housing drain

2. Pump expansion joint



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3. Pump inlet flange4. Pump floor-mount flange5. Pump shaft seal6. Pump-housing penetrations

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

G. Air-removal equipment1. Steam jet air ejectors

a. Flange and threaded connectionsb. Inter-condenser penetrationsc. Condensate drain seald. Isolation valvese. Drains

2. Mechanical vacuum pumpsa. Flanged and threaded connectionsb. Shaft sealsc. Air jetsd. Isolation valvese. Cylinder head (piston-type)

Many air-removal configurations incorporate air-assisted jets to accelerate the off-gas flow to thevacuum pumps. These jets pull in large volumes of ambient air, which is funneled into the off-gas stream. These jets must be valved out when performing the leak test because the largevolume of the assisting air ~100 scfm (170 cubic meters/hr) dilutes the tracer gas concentrationin the off-gas.

A drawing should be made for each low-pressure turbine and for each exposed condensersection. Penetration numbering should follow the sequence of the testing order. Details such asthe Plant North orientation and penetration numbers cross-referenced to piping installationdiagrams should be included. Figure 7-6 is an example of a drawing.



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Figure 7-6Condenser Penetration Map [3]

It is not recommended that complete installation diagrams be included in the checklist. Due totheir large size and complexity, they do not readily facilitate testing. Instead, the relevantdrawings should be extracted from the larger diagrams and reduced to a size convenient forinclusion in the checklist document.

The draft checklist should then be rewritten into a format that allows recording of theinformation gathered during the air in-leakage test.

Finally, the completed checklist should be reviewed to verify that it details the requiredequipment checks in the order in which the test will be performed.



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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 areso excessive that the unit cannot be maintained on-line.

The process of condensing steam creates a partial vacuum in the condenser. Non-condensablesare removed by pumps. Typically, the inlets for these pumps are located near the air-removalsection of the tubesheet, close to the bottom of the condenser and just above the hotwell. Thedownward flow of steam from the turbine exhaust propels the non-condensables toward the air-removal 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 allareas of the condenser. Movement of the flow of this air mass is only a gradual migration fromthe in-leakage points to the air-removal inlet. Additionally, the air-removal equipment will beoperating 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-linegenerally meet with failure. With no steam to hasten the removal of the tracer gas, the signalresponse time will be slow, the signal will take several minutes to peak, and it will require manymore minutes to clear out. Performance of an air in-leakage test with steam in a bypass modewill not provide satisfactory results. Typically, bypass steam dumps into one side of a condensersection at an elevation lower than the uppermost condenser tubes. Steam entering at such alocation 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 iswhen high in-leakage rates prevent the unit from being brought on-line. Depending on the size ofthe condenser and the installed air-removal equipment, this would be an in-leakage rate of 80scfm (136 m3/hr) or more. Two differences from the normal test conditions would make this testfeasible:

x The large volume of air leaking into the condenser creates an acceptable flow of non-condensables 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 unitfrom being brought on-line. Once found and corrected, the unit is put on-line and normaltesting can continue.

The test equipment setup for off-line testing is the same as for on-line testing. In addition to thetest 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 increaseby hundreds of cubic feet (cubic meters) per minute.

Small condenser leaks might not show any indication due to the dilution caused by the greatvolume of air entering the condenser through the large leak. However, when the tracer gas isreleased in proximity to the large leak, more of the tracer gas will be drawn into the condenser,thereby helping to offset the dilution.



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When the leak indication is identified, the leak isolation process continues in the manner of theon-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) instrumentshown in Figure 7-7.

Figure 7-7Multisensor Probe [3]



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This instrument, with its sensor located in the exhauster vacuum line, has the ability to measurethe precise amount of air in-leakage entering the condenser. At the same time, the instrumentalso measures the exhauster capacity. This indicates whether it is responsible for the excessbackpressure. With a sensor in each air-removal line leaving the condenser, the search field forusing the tracer gas can be reduced to the number of lines monitored. Any leak into a condensersection will be largely removed by its air-removal section. Leaks can be measured with thisinstrument below the level that affects the condenser backpressure. For example, air in-leakagecould 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 beused to monitor air in-leakage while applying temporary fixes to suspect areas. The responsetime is 30 seconds to 3 minutes after application of a fix to a leak area. Some common fixesinclude the application of duct tape, plastic wrap, and putty. A benefit of this method is that theprecise 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 InfraredTechnology (IRT). Air in-leakage, as seen through the infrared camera, appears as a cool areasurrounding a void. The void can be found through the convective effects on the surfacesurrounding the opening when the surface of the component being viewed has a differentialtemperature 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 theamount of air being drawn through the opening will change as the internal processes change. Asthe 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-pressureturbine 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 orsulfur 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 inspectionmethod.

x Some of the identified leaks with this method can be verified by the temperature changes ofthe 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.



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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 judgmenthas to be exercised when determining how to conduct the repair and how permanent to make it atthat time. Much will depend on the severity of the leak. If the leak can be reduced to anacceptable level without taking the unit out of service, this might be more important thanproviding 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 orreplace piping or pipe fittings where air is leaking into areas of the condenser and turbinesystem that operate under sub-atmospheric pressures. In the case of leaks detected in anypiping that lies within the waterbox, the pipes should be corrected or replaced before the unitis brought back on-line. Leaks found in those pipes that have easy external access can becorrected or replaced in accordance with good practice. Often these pipes can be repairedwith 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 inwelds around the penetration. These can often be corrected while the unit remains inoperation.

x Sealants — Many commercial sealants are available to the utility industry for correctingsources of air in-leakage. The selection depends on how they have to be applied, theirviscosity during application, and the temperature conditions in which they have to operate. Itis important that materials retain their flexibility at ambient temperatures and that they do notharden and become brittle when their temperature is raised. The use of sealants made fromsilicone-based materials is preferred.

Many of the areas in a condenser that are prone to air in-leakage operate at below-atmospheric pressure. Sealants applied at the surface tend to be drawn into the opening orcrevice, as long as the viscosity remains low. Such sealants can be applied successfully to theexposed interfaces between stationary components such as pipe or valve flanges.

x Component repair and/or replacement — Good engineering practice will determine howleaks in condenser or turbine components should be repaired. With small cracks, the use ofsealants might be considered. Welding or brazing of the component might also be apossibility 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 theunit shut down. However, they seem to leak when the unit is on-line and returns to normaltemperature conditions. It is possible that the internal surfaces of the seals might havebecome worn and the radial clearance is excessive. It might be necessary to repair or replace



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

x Packing adjustment — Leaking packings on valves or the seals on rotating shafts of smallequipment can often be replaced without shutting the unit down. This is true if redundantbackup equipment can be brought into operation. This allows the faulty equipment to betaken 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 on-line. 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 thebolts be removed before the packing can be replaced. This normally involves the unit beingtaken 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 cmHgA), 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, thecooling water chemistry is usually maintained at higher levels of impurities. This is the result ofusing raw water drawn from lakes or rivers or cycled through cooling towers. This water cancontain chemicals added to control biological fouling, scale and/or silt. When condensatecontamination occurs, the amount depends on the chemistry of the cooling water and the size ofthe leak.

Circulating water in-leakage into the condenser has been the major source of impuritiesintroduced into the condensate and a major factor in corrosion. There are a number of possiblecauses of water in-leakage, including:

x Improperly rolled tube joints

x Poor condenser design leading to tube failures caused by steam impingement or from damageby 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 waterand the high-grade condensate. Due to the vacuum inside the condenser, any tube leakage willcause contamination of the condensate by the cooling water. This can lead to increased corrosionof the secondary system.



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Key Technical Point

Prevention of cooling water in-leakage is important in all cooling watersystems. It becomes critical when brackish water or seawater is used forcooling. 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 seriousbecause it allows corrosives and other undesirable dissolved solids to gain entry into thecondensate hotwell. Condensate polishing demineralizers, if available, deplete rapidly and arenot a long-term solution to the problem. Left unchecked, leaks will eventually cause seriousdamage to the piping, steam generators (or boilers), and turbines. Required response times forsuch leakage events are generally short and governed by the chemical composition of thecirculating water and the size and number of leaks.

On-line leak detection and/or chemistry indications can determine the tube bundle that containsthe 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 thechemistry of the circulating water. Each plant must plan its own chemistry response to acondenser in-leakage event. For example, plants using seawater as their source for circulatingwater see very large chemistry changes in the condensate for very small leaks. This is because ofthe large amount of total dissolved solids in seawater. Plants operating with a relatively purefreshwater lake as their source for cooling water might see only minor changes in the condensateduring even large condenser in-leakage events. If such plants have recirculating steamgenerators, they might see chemistry changes in the steam generator blowdown before it can bedetected 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 anon-line conductivity that is near theoretical (0.054 Pmhos/cm), often use specific conductivity asan indicator of condenser water in-leakage.


Most plants use continuous monitoring of cation conductivity in thecondensate, feedwater, and/or steam generator blowdown as the primaryindication of the presence of condenser in-leakage.

Cation conductivity is easily measured and can be monitored on-line by a fairly simple andrugged apparatus. Normally a sampling tray is provided under each tube bundle. The condensatein this tray is continuously monitored for conductivity. If the conductivity exceeds a certain limit,an alarm is received, indicating a possible tube leak.



7-27

Sodium is the principal cation present in most cooling waters and sodium monitoring is oftenused 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 thewater chemistry of most power plant systems. Most plants have on-line sodium monitorsinstalled. On-line sodium monitors are more expensive and require more attention than on-linecation conductivity monitors.

On-line sodium monitors are designed to continuously monitor trace levels of sodium inrelatively pure waters. Typical on-line sodium monitors measure sodium content from 0.1 to1000 ppb, but higher or lower ranges are possible, particularly in microprocessor-controlledinstruments.

Grab samples for chlorides in the condensate, feedwater, and/or steam generators are typicallyused to provide confirmation of the leak presence. Also, the presence of chlorides in combinationwith 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 seawateror brackish water). On-line chloride monitors can be used to monitor condenser in-leakage. On-line chloride monitors are more expensive than sodium monitors and require more attention thanon-line conductivity monitors.

Other chemical species, such as sulfate and silica, can be used to establish cation-anion ratios toconfirm the source of in-leakage. It typically takes longer to complete their analysis than thosemethods used to determine the analysis of the other species discussed earlier. Also, grab samplesmust be used for the analysis because plants might not have on-line analyzers set up to monitorsilica and sulfate in the condensate, feedwater, and steam generators.

Condenser in-leakage can result in challenges to chemistry limits established to protect plantsystems. These limits have been developed in plant, type-specific chemistry guideline documentsand are further refined by site-specific chemistry program limits.

On-line monitors on the condensate, feedwater, and/or steam generator (boiler) blowdown willgive the first indication of a leak. The leak can then be confirmed with grab samples. An estimateof the leak rate can be made using the following formula:

LRCT = (FRFW) (C1)/C2) (eq. 7-7)

where,

LRCT = Condenser tube leak rateFRFW = Feedwater flow rateC1 = Concentration of the chemical of interest in the condensateC2 = 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 tubebundle containing the circulating water leak. If the leak is too small to be detected in the hotwellsampling, lowering the power level will concentrate impurities by decreasing steam/condensate



7-28

flow while the in-leakage remains constant. This can bring impurities within analytical detectionlimits.

When the leaking bundle has been identified, its cooling water supply can then be isolated andthe bundle drained. This procedure accomplishes two things:

x It significantly speeds up the identification of specific leaks by immediately eliminating anytesting 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 necessaryand not a forced outage. This assumes that the condenser design permits waterbox isolationoperation.

Power should be reduced to the point where steam flow over those tube bundles left in servicedoes not exceed the normal full power flow rate with all bundles in service. After ventilationflow in the waterbox is established, and staging and work platforms have been placed in thewaterbox, several methods of cooling water leak location can be utilized.

Isolating tube bundles sequentially is an alternative to hotwell segregation. When the leakingtube bundle is isolated, hotwell cation conductivity will change. If leaks exist in more than onebundle, however, this method might not work.

Unfortunately, if the condenser leak is large enough or is allowed to exist for too long a period oftime, plant chemistry limits in the condensate, feedwater, and/or steam generator (boiler) mightbe 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 andfeedwater heater chemistry. Cooling water in-leakage through the main condenser is a majorconcern. This cooling water might be raw lake water, brackish water, seawater, or chemicallytreated cooling tower water.

Water in-leakage allows contaminants to enter the condensate and cause corrosion in many partsof the feedwater, steam generator, and turbine systems. General corrosion, pitting, stresscorrosion, corrosion fatigue, and their combinations are the major corrosion mechanismsresulting from the concentration of corrosive substances in the turbine. While general corrosioncauses little problem, failure of turbine parts resulting from pitting, stress corrosion, andcorrosion fatigue often result in catastrophic failures and long costly outages. They have beencharacterized 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



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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 thetendency for them to become concentrated.

Contaminants can enter the secondary system through leaks in the condenser itself, which candevelop in the joints between tube and tubesheet or through-wall penetrations. Contaminants canalso enter from the condensate polishers. This tends to imitate a condenser tube leak. Resin orresin fines can also leak through the tubes and enter the system.


Water chemistry guidelines for PWR once-through and recirculating steamgenerators can be found in EPRI TR-102134-R5, PWR Secondary WaterChemistry 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 aspecific plant is based on the removal capabilities of condensate purification equipment. Forexample, a plant with deep-bed demineralizers can tolerate higher leak rates or leakage for alonger 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 fixingin-leakage must be analyzed so that the appropriate opportunity to identify and correct theleakage can be selected. Items that should be considered in the decision-making process includebut 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 theconstruction of the BWR need to be analyzed to ensure that maximum material longevity can bemaintained.



7-30


Water chemistry guidelines for BWR units can be found in EPRITR-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, andcigarette smoke in attempting to find the leaking tube. Some individuals believed that they couldfind a tube leak by placing an ear on the tubesheet. Unfortunately, out of the millions of tubesthat have been inspected, very few tubes have been heard to be leaking. Meanwhile, othersbelieved that they could locate a leaking tube by simple observation.

All of the above intuitive techniques have their shortcomings so far as reliability, accuracy, andcost-effectiveness are concerned. None of these techniques offers a means of verifying, prior toputting the condenser back on-line and then checking the chemistry, that the suspected tube wasthe one actually leaking. These techniques are not supported scientifically and they all rely on theintuitive sense of the technician.

Most leak-detection methods involve draining the waterbox that is to be inspected with the shellside of the condenser still under vacuum. With only one waterbox out of service, it is possible toperform a leak test under partial load. However, it is difficult to perform in-leakage testing withthe unit shut down completely. The air-removal vacuum system might be able to lowercondenser backpressure sufficiently when working alone. A major problem with all of thesetraditional methods is their uncertainty. To ensure that the leak has been sealed, the tubeidentified as leaking has to be plugged. A number of the surrounding tubes also have to beplugged.


Even when the leaking tube has been positively identified, insuranceplugging can be considered good maintenance practice. In many cases, theexact mechanism that caused the tube to fail is uncertain. Selectingsurrounding tubes to be plugged is insurance against additional leaksdeveloping before the next outage. Those tubes with insurance plugs can thenbe subjected to eddy current testing during the next outage so that as manytubes as possible can be returned to service.



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Once the leaking bundle has been identified, a number of methods areavailable to determine exactly which tubes or joints are leaking. All of themethods commonly used involve testing areas of the tubesheet sequentiallyuntil the area of the leak(s) is evident. Testing then progresses to smallerareas until the exact leak location is found. The most commonly utilized leaklocation methods are tracer gas, plastic film, soap film NDE, smoke, waterfill, 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 aburst through a hose to plenum hood. The hood is held over a section of the tubesheet. A bloweror eductor must be in operation in the waterbox on the opposite end of the condenser from thetest area. This is necessary to ensure that the helium gas will be drawn through the entire lengthof each tube tested. A helium probe sniffer connected to a spectrophotometer is attached to thedischarge of the air ejectors or vacuum pumps. If a leak is present, the helium gas will appear onthe steam side of the condenser and be transported by steam to the air-removal units. It isnecessary for the unit to be at a minimum of approximately 20% of its full power rating to ensuresufficient quantities of motive stream. Helium does not diffuse readily and will tend to remain inan area unless a transport medium is present.

Normal practice is to test 50-100 tubes in an area. Once a leaking area is located, smallernumbers of tubes/joints or each tube/joint in the leaking area are tested to identify the exactleaking tube/joint. When testing individual tubes/joints, all tubes surrounding the test subjectmust be plugged. Leaks as small as 1 gallon per day (3.8 liter/day) can be detected with thismethod.

Sulfur hexafluoride gas can be utilized by mixing the gas with air and testing in the samemanner. The main advantage of testing with sulfur hexafluoride is ease of detection anddecreased 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 inletand outlet ends of the condenser. Vacuum is maintained on the shell side. The plastic film will bepulled into the leaking tubes. A search is made for any areas where the wrap appears to besucked into a tube. It is not necessary to cover the entire tubesheet at one time. A procedure canbe adopted in which only a section of the tubesheet is covered and then inspected before movingon to the next section.



7-32

This method fails to detect small leaks and is ineffective for joint leaks. Each tube in a groupmight 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 onlyplaced at one end of the unit with the opposite end being covered by soap foam. Any tube/jointleaks will cause a collapse of the foam in the leak area and thus reveal the leak location. Thismethod 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 creamhave 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 arethen plugged.

7.5.4 Non-Destructive Methods

Other methods that can be utilized to detect leaks are infrared, eddy current sonic pulse, andultrasound. Each of these methods is accurate and requires specially skilled personnel toperform. For a more complete discussion of these techniques see Recommended Practices forOperating 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 waterboxhas been drained, a technician enters and partially closes the manway. The technician proceeds tolight up and hold a smoke generator (often a cigarette) in front of individual tubes. It is observedif the smoke is drawn into the tube. The distance of the leak from the face of the tubesheet mightaffect 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 stopperswith a thin membrane that covers a hole formed through the stopper. Both types have been usedsuccessfully 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 endof the tube and allowed to stay in place for as long as 12 hours. If leaking, the tube is now undervacuum. When later removing the stopper from one end, personnel can confirm that the tube isleaking 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 ofthe membrane-type stoppers is installed in one end of the tube while a solid rubber stopper isplaced in the other. The suction created within a leaking tube results in a visible depression onthe membrane covering the end of the specialty rubber stopper.



7-33

Because membrane rubber stoppers do not require a long soak time, even small leaks can bedetected 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 isaccomplished by blocking both ends of a suspect tube, pressurizing or evacuating the tube, andthen 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 fewminutes spent using this method to test one or two rows of tubes surrounding a suspect or leakingtube will not only confirm the leak but will also identify any additional leaking tubes. This mighteven eliminate the need to install insurance plugs. However, if the objective is to test the entirecondenser, 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 orplacement of the unit back into service. Water filled leak testing is normally employed as thefinal test for tube-to-tubesheet joint integrity.

The specific procedure for hydrostatic testing of condenser tube joints is dependent upon thecondenser system setup at the particular plant. However, a few general precautions andrecommendations 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. Condensationmakes 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 andre-rolled. A good rule of thumb is to fill it at a rate of approximately 3 feet/hour (1.5cm/min). If gross leaking occurs, filling should be stopped and all leakers re-rolled before re-initiating 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 thebundles. After the test height has been reached, the level should be maintained forapproximately 12 hours. The tubesheets should then be carefully reinspected. Should morethan 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 beensustained by piping that had been allowed to run through a waterbox. An example would bedrain piping from a low-pressure turbine bearing, which could be placed only vertically andimmediately below the bearing, thus being forced to penetrate the waterbox. Leaks from suchsources are hard to locate even when using sensitive tracer gas techniques, partly because they



7-34

are somewhat hidden from view, but often because their leak rates are very small. In addition tonoting the obvious, the importance of studying plant drawings and identifying all such obscuresources of potential leaks cannot be stressed enough.

7.5.10 On-Line Leak Detection [26]


EPRI has developed and patented a system that uses targeted injection ofsulfur hexafluoride (SF6) to detect and locate condenser tube leaks while thecondenser is in full operation. The system is called the Condenser On-LineLeak Detection System (COLDS) and a description of it is found in EPRIdocument AP101840-V3P2, published in December 1995. It can locate leakswith flow rates as low as 1 gallon (4 liters) of water per day and small leaksthat cannot be located with off-line techniques.

Figure 7-8 shows the schematic of the COLDS.



7-35

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

In the COLDS, SF6 tracer gas is mixed with water and introduced into the condenser tubesthrough 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 leakis 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 maintainedacross the two electrodes, causing a small electric current to flow across the air gap between theelectrodes. The gas sample is pumped into the cell where it passes between the electrodes, isionized 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



7-36

concentration of SF6 in the sample. With this technique, levels of SF6 down to 0.1 ppb aredetectable.

The lance assembly is designed to replace existing manway covers on inlet waterboxes and canbe installed during an outage. The injection lance is positioned coaxially within a tubularhousing. This is affixed to a swivel mount and passes through the port in a ball valve. The innerportion of the lance is inside the waterbox and the other end extends outside. The lance can beadvanced and retracted axially within the housing; the swivel ball joint can be rotated to placethe lance in a desired angular position. A range of areas and locations on the tubesheet can betargeted. The lance targeting method consumes less tracer gas than bulk injection does.

This system is designed to monitor lance position by using linear variable differentialtransformers (LVDTs) coupled with a personal computer. An LVDT is a ruggedelectromechanical device that produces an electrical output proportional to the displacement of amovable core. In this system, three LVDTs, spaced equally about the axis of the lance, producesignals that are sent to the computer. These are used to determine the position of the lancerelative 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. Havingfound the source and nature of the leak, it might be prudent to perform a failure analysis. It is notenough to correct the immediate problem; steps should be taken to determine the extent of thedamage to other parts of the tube bundle by, for example, eddy current testing of a selected set oftubes.

How to prevent or delay the occurrence of similar in-leakage problems in the future should be astrategic concern. If corrosion was due to deposits not being removed soon enough, then a morefrequent tube cleaning program should be instituted. If the corrosion was caused by the chemicalcomposition 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 corrosionwas due to galvanic action between incompatible metals. All these failure modes require theirown 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, re-expanding the tube-to-tubesheet joints, coating of tubesheets, retubing, staking tubes, waterboxrepairs, tubesheet repairs, and miscellaneous repairs.

If the water in-leakage was due to the erosion/corrosion of tube inlet ends, this can often becircumvented by placing plastic inserts, thin-walled metal inserts, or shields in the tube inletends. 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 bereduced by staking the tube bundles appropriately. Please see Section 10 of this guide forinformation on maintenance repairs.



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


8-1

8 FAILURE MODES

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

8.1 Failure Data

There are several operational and maintenance databases available from the Institute of NuclearPower Operations (INPO), the Nuclear Regulatory Commission (NRC), and the Operating PlantExperience Code (OPEC).

INPO identifies and communicates lessons from plant events so that utilities can take action toprevent similar events at their plants. Events are screened and analyzed for significance andthose with generic applicability are disseminated to the industry as Significant Event Evaluationand Information Network (SEE-IN) documents. The following are some applications thatprovide access to INPO and industry operating experience information:

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

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

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

The following is an application from the NRC:

x The Licensee Event Reports (LERs) database contains searchable event information fromthe NRC reporting system. This information can be searched for plant events that haveoccurred since 1984.

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


Failure Modes

8-2

8.1.1 Just-in-Time Operating Experience

There have been four incidences of injuries from use of the hydrolaser. The hydrolaser is adevice that cleans condenser tubes. Water at pressures up to 10,000 psi (69 megapascals) issupplied from high-pressure hoses to a nozzle attached to a lance. Personnel guide the lance toeach condenser tube to inject the high-pressure water to clean debris from the tube. See Table8-1 for a listing of the injuries.

Table 8-1Injuries from Hydrolaser Use (from INPO JIT data)

Date Injury Cause

4/11/00 Small puncture in arm Contractor did not use required safetyprotection equipment on lance.

7/20/99 Minor laceration on toe Mechanic was not in correct position to holdHydrolaser when trigger was depressed.

4/27/99 Laceration on finger The hose of the wand became entangled andthe left hand passed in front of the wand.

1/8/99 Severe hand cut Worker was not prepared for the reactionforce of the wand when the water was turnedon.


INPO determined that the following are causes of personnel injuries fromHydrolaser use:

x Improper work practicesx Inappropriate personal protection equipmentx 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 equipmentfor the years 1981-2000. There have been twelve events during that time.


Failure Modes

8-3

Table 8-2INPO SEE-IN Experience Information

Date ofNotice

Plant Event Description

1/25/00

OE 11065

Farley 1 Power reduced to 62% because ofleak in expansion bellows ofextraction steam line

Expansion bellows cracked fromfatigue caused by steam flowvibration and age.

1/5/00

OE 11554

Palo Verde 2 Unit shutdown on high sodiumlevels in steam generator

Condenser tube leak caused by11 failed expansion joints fromvibration-induced high-cyclefatigue.

7/30/99

SEN 200

Hatch 2 Low condenser vacuum manualscram due to waterbox airentrapment

The unit was manuallyscrammed on low condenservacuum. The loss of vacuumresulted from waterbox airentrapment created by loweringthe circulating water pumpsuction intake level forchlorination activities, anineffective waterbox continuousvent modification, andatmospheric conditions.

4/19/96

SEN 130

SER 7-96

CrystalRiver 3

Saltwater intrusion caused by maincondenser tube rupture

Catastrophic failure of onecondenser tube allowed ingressof saltwater into the hotwell. Thecondensate and feedwatersystems were contaminated withchloride, sodium, and sulfateand the unit was shut down.

3/8/95

OE 7271

Sequoyah 2 Unit shutdown due to condensertube leak and 5 Mw reduction

Failed extraction line bellowsexpansion joint.

6/13/92

OE 5371

MaineYankee

Unit shutdown due to low, low-pressure steam supply tofeedwater pump turbine

Failed extraction expansion joint.


Failure Modes

8-4

Table 8-2 (cont.)INPO SEE-IN Experience Information

Date ofNotice

Plant Event Description

2/28/91

O&MR 385

Zion Sudden loss of condenser vacuumdue to condenser boot failure

9/90 - a 4-foot (1.2 m) section ofthe rubber condenser boot failed

8/89 - a 3- foot (91 cm) sectionof the condenser boot was torn

7/89 - condenser boot failurefrom aging, over-tightening bolts,and steam impingement

9/87 - an 8-foot (2.4 m) sectionof the rubber condenser bootfailed

1/85 - condenser rubber bootfailed

1&2/84 - condenser boot failurefrom overheating

3/18/87

O&MR 318

VermontYankee

Steam intrusion into maincondenser during maintenance

Steam intrusion into a tagged-out condenser. A feed-waterrecirculating valve was open inthe adjacent condenser that wascon-nected to the tagged-outcondenser by an equalizing line.

2/16/86

SER 27-86

PeachBottom 3

Unplanned radioactive release dueto a blown fuse in the maincondenser hotwell level controlsystem

A blown fuse in the hotwell levelcontrol system allowedcondensate to overflow thecondensate storage tank, flow tothe storm drain system, and intothe river.

10/4/85

O&MR 276

AlabamaPower,Penn. P & L

Legionella bacteria in plant coolingtowers and condensers

Presence of legionella bacteriafound in sludge. Respiratoryprotection required by twoutilities.

7/14/83

O&MR 148

San Onofre 2 Water hammer in steam bypasscontrol system damagedcondenser

Piping damage from waterhammer in steam bypass controlsystem.

8/12/81

SER 62-81

PeachBottom 2

Results of oil intrusion into maincondenser hotwell

300 gallons (1,135 liters) oflubricating oil flowed from thefeedwater pump bearings.

8.1.3 Licensee Event Reports (LERs)

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


Failure Modes

8-5

planned for coverage in an EPRI Expansion Joint guide scheduled for release in the 2001-2002time period.

Table 8-3Licensee Event Reports for Main Condenser from 1984 to Present

Date Plant Event-Reactor Trips Description

11/16/97 Robinson 2 Low feedwater flow tosteam generator

Condensate pump stub shaftfailure, cyclic fatigue fromfaulty design on keyway.

11/26/95 Palo Verde 1 Turbine trip on lowcondenser vacuum

Faulty o-ring in solenoidcaused two vacuum breakervalves to leak.

9/30/95 Brunswick 1 Condensate feedwatertransient

Air in-leakage caused airbinding in both condensatepumps.

7/17/92 ShearonHarris 1

Low condenser vacuum Low-pressure turbineexhaust boot seal failure,routine fatigue by aging.

7/12/92 ShearonHarris 1

Low condenser vacuum Low-pressure turbineexhaust boot seal failure,routine fatigue by aging.

6/24/92 Calvert Cliff 2 Low condenser vacuum Failed condenser expansionjoint due to aging.

12/20/91 Washington 2 High reactor coolantconductivity

Main condenser tube leak.

9/7/90 Zion 2 Loss of condenser vacuum Condenser boot failure.

8/14/89 Grand Gulf 1 Loss of condenser vacuum Condenser expansion jointfailure.

7/16/89 Diablo Canyon 2 Condensate high cationconductivity

Condenser tubesheet plugfailure.

7/14/89 Clinton Loss of condenser vacuum Failed rubber expansionjoint from age, over-tightening clamp assembly,and steam exposure fromdetached protection cover.

1/20/88 Grand Gulf 1 Low reactor water level Leaking condenser watermanway cover sprayedwater on hotwell levelswitches.

6/1/87 D.C. Cook 2 Loss of condenser vacuum Failed manual isolationvalve allowed air in-leakagefrom the open drain tankdischarge header.

4/9/87 Dresden 3 High condensatetemperature and lowcondenser vacuum

Turbine bearing conewastewater and oil drain lineunion broke insidecondenser.


Failure Modes

8-6

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 onfeedwater pump

Failure of condenser leveltransmitter locknut.

9/27/86 Dresden 3 Low condenser vacuum Circulating water flowreversal valve failure.

7/26/86 San Onofre 3 Loss of feedwater Automatic rejection ofcondensate contaminated bycondenser seawater in-leakage.

4/11/85 R. E. Ginna 1 Low condenser vacuum Isolation and venting ofcondenser section to findbaffle plate failure.

1/16/85 Quad Cities 2 Loss of condenser vacuum Failed rubber expansionjoint.

12/18/84 St. Lucie 2 Low steam generator level Poor venting technique forcondensate pump causedcavitation and pump trip.

8/2/84 Columbia 2 High reactor waterconductivity

Condenser tube leak.

4/26/84 LaSalle 2 Manual scram to preventequipment damage

Stuck recorder pen on thelevel recorder in the controlroom, suction strainers oncondensate pumps plugged.

2/13/84 LaSalle 1 Loss of condenser vacuum 14th stage extractionexpansion joint failed,rupturing the boot sealbetween the condenser andturbine.

1/16/84 LaSalle 1 Low condenser vacuum 16th stage extractionexpansion joint ruptured andcaused the rubber boot sealto rupture.

8.1.4 Plant Events Database

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


Failure Modes

8-7

Table 8-4INPO Plant Events Database for Condensers

Date Plant Event Failure

9/18/00 Columbia 2 Decrease in vacuum Turbine oil, water drainbroke in condenser.

9/13/00 Vermont Yankee 1 Loss of vacuum Ejector steam supply valveclosed on loss of motorpower.

8/31/00 Diablo Canyon 2 Extraction line expansionbellows failure

Damaged condenser tubecausing leaks.

6/6,7,18/99

LaSalle 1 Leakage from lowermanway on condenser

Improper gasket material,poor condition of manwaysealing surface, and boltsinsufficiently tightened.

2/21/99 Grand Gulf 1 Manual scram fordecreasing condenservacuum

Condenser seal improperlyvulcanized and joint failed.

12/3/98 Peach Bottom 3 Condenser tube leaks Baffles were not deflectingsteam from impinging ontubes.

11/14/98 Surry 1 Water chemistry chlorideand sodium levels incondensate too high

Tube plugs missing.

6/3/98 Oconee 2 Loss of condenser vacuum Vacuum was lost throughan open auxiliary steamvalve during maintenance.

5/20/98 Ark. Nuc. One 1 High sulfate concentrationin condensate


9/10/97 Fort Calhoun 1 High levels of sodium incondensate


4/22/97 E.I. Hatch 2 Low condenser vacuum Loss of ejector and airentrainment in thecirculating water system.

1/9/96 Crystal River 3 High levels of chloride,sodium, and sulfate incondensate


7/14/95 D.C. Cook 1 Loss of condenser vacuum Broken weld on a 1-inchsteam dump valve drainallowed air intrusion.

7/12/95 Grand Gulf 1 Low condenser vacuum Degradation of condenserexpansion joint seal.

3/8/95 Sequoyah 2 Condenser tube leak Extraction line bellows hadblown out.


Failure Modes

8-8

Table 8-4 (cont.)INPO Plant Events Database for Condensers

Date Plant Event Failure

4/29/94 Millstone 3 Condenser waterboxrupture

Outlet valve closed in full-flow conditions due to aninadequately designedspline adapter to the shaftinterface.

1/11/94 Catawba 1 Low condenser vacuum Heater extraction linesheared off from vibration-induced fatigue.

11/4/93 Three Mi. Island 1 Partial loss of condenservacuum

Improper installation ofdiaphragm in air-operatedsolenoid valve for the air-removal pump dischargevalve that allowed air in-leakage.

10/22/93 E.I. Hatch 1 Condensate pumpstripped

Partition plate incondenser broke and hit abrace. This causedvibration that tripped thehotwell level switch.

7/17/92 Shearon Harris 1 Low condenser vacuum Failure of the turbineexhaust boot seal.

7/12/92 Shearon Harris 1 Low condenser vacuum Repair of condenserexpansion joint.

6/24/92 Calvert Cliffs 2 Loss of condenser vacuum Failed condenser

expansion joint.

11/16/91 Clinton 1 Decreasing condenser

vacuum

Condenser suctionisolation valve open.

9/7/90 Zion 2 Loss of condenser vacuum Failed expansion boot.

7/15/90 Limerick 2 Low condenser vacuum Low-pressure turbinewaste 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 tubeleaks from April 1998 through June 2000. For the twenty-seven months of the data given, therewere forty-four outage events because of tube leaks. Of these forty-four events, twenty-sixevents resulted in a forced outage, sixteen events resulted in a scheduled outage, with two eventsunknown.


Failure Modes

8-9

Table 8-5OPEC 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 Load reduction to 96%

04/08/00 Robinson 2 Scheduled Load reduction to 50%

03/28/00 Turkey Point 4 Unknown Load reduction to 60%

03/18/00 Robinson 2 Scheduled Load reduction to 50%

03/10/00 Three Mi. Island 1 Forced Load reduction to 50%

01/28/00 Nine Mi. Point 1 Forced Load reduction to 50%

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 Load reduction to 70%

11/04/99 FitzPatrick Forced Load reduction

10/30/99 FitzPatrick Forced Load reduction

10/05/99 Beaver Valley 2 Scheduled Load reduction to 90%

10/01/99 Beaver Valley 1 Scheduled Load reduction to 90%

08/06/99 Beaver Valley 1 Forced Load reduction to 91%

07/10/99 Peach Bottom 3 Forced Load reduction to 62%

06/01/99 North Anna 1 Unknown Load reduction to 85%

05/12/99 Hope Creek 1 Forced Load reduction

05/07/99 Palisades Scheduled Off-line tube plugging

04/30/99 LaSalle 2 Forced Load reduction

04/16/99 Ark. Nuc. One 2 Scheduled Load reduction to 75%

04/12/99 North Anna 1 Forced Load reduction to 95%

04/09/99 Fermi 2 Scheduled Load reduction to 47%

03/16/99 Diablo Canyon 1 Forced Load reduction to 50%

02/24/99 Beaver Valley 1 Forced Off-line tube plugging

02/14/99 Beaver Valley 1 Forced Shutdown

01/01/99 Watts Bar 1 Forced Load reduction to 65%


Failure Modes

8-10

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


10/28/98 Millstone 3 Forced Shutdown

09/25/98 Palisades Scheduled Load reduction to 44%


08/27/98 Millstone 3 Scheduled Load reduction


08/21/98 Shearon Harris 1 Scheduled Load reduction to 30%

07/19/98 Perry 1 Forced Load reduction

06/07/98 Ark. Nuc. One 2 Forced Load reduction to 70%

05/21/98 Three Mi. Island 1 Scheduled Load reduction to 50%

05/20/98 Ark. Nuc. One 2 Forced Shutdown

05/08/98 Ark. Nuc. One 2 Forced Load reduction to 70%

04/24/98 Three Mi. Island 1 Scheduled Load reduction to 50%

04/24/98 Shearon Harris 1 Scheduled Load reduction to 30%


8.2 Failure Mechanisms [27]

While there are numerous failure mechanisms for condenser components, this report will addressthe 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 theair-removal section. Deep circumferential grooves can occur in areas of localized condensateflow. 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 bufferpH. These chemicals, typically hydrazine and various amines, can undergo thermaldecomposition in the high temperature zones of the reactor/boiler to form ammonia. Thisammonia, along with other non-condensable gases, tends to collect in the air-removal section ofthe condenser. These non-condensable gases dissolve in the condensate, resulting in anoxygenated, 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 theproblem.


Failure Modes

8-11

Failure Prevention Practice — Reduce the oxygen levels and use a stainless steel or titaniumtube 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 directexposure to the cooling water. Corrosion is accelerated inside or immediately adjacent to thecrevice. This can occur at the tube-to-tubesheet joint, at the interface between inlet end inserts, orbeneath deposits. Crevice corrosion has been reported in stainless steel and copper-alloy tubes.Crevice corrosion susceptibility is increased with increasing water temperature or chlorideconcentration. It is also influenced by the tightness of the crevice. A picture of crevice corrosionis shown in Figure 8-1.

Figure 8-1Crevice Corrosion [24]

Failure Prevention Practice — Eliminate tube-to-tubesheet crevice by seal welding the joints instainless 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 anelectrochemical process. Dealloying occurs on the tubesheet and waterbox. It can be difficult todetect visually because of the lack of significant dimensional change.


Failure Modes

8-12

Muntz metal is composed of ~60% copper and ~40% zinc (ASTM B171). For tubesheets madeof Muntz metal, a dealloyed area will often exhibit a bright copper-colored appearance once thethin, dull surface layer is removed. If dealloying is suspected, the area should be probed with aknife or chisel to detect the presence of a weak, spongy structure.

The most common dealloying mechanism is dezincification, the selective leaching of zinc frombrass alloys. Dealuminumification involves the loss of aluminum and denickelification the lossof 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 similarto general corrosion, with little or no discernible change in overall dimensions. In the case ofcopper-based alloys, the surface appears reddish at areas where the active component hasdissolved. This attack occurs in low hardness, low pH waters under stagnant conditions, and isaccelerated by chloride and sulfate ions. Differential oxygen cells beneath deposits can alsopromote attack.

Plug-type dezincification is similar to pitting attack. This is the more dangerous form becauseattack can cause failure through penetration. This localized attack usually attains a significantdepth perpendicular to the metal surface. It is promoted by alkaline corrosive media, localdeposits, and discontinuities in the protective oxide film. Aluminum brass is particularly prone tosuch attack. Figure 8-2 shows a picture of plug-type dezincification.

Figure 8-2Plug-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 ofcopper


Failure Modes

8-13

Depending on the various solution factors, it is highly probable that both mechanisms occur atthe same time.

The seriousness of the attack on commercial brasses depends on the application. For brasses usedin heat exchanger tubes, plug-type dezincification becomes more serious because of its depth ofpenetration relative to overall tube wall thickness. The same type of attack on tubesheets hasnegligible consequences. Layer dezincification might waste more metal from the entire surfacethan plug attack but it is a less serious condition.

Key Technical Point

Dezincification of Muntz metal is the most commonly reported dealloyingproblem in condensers. In the absence of other corrosion acceleratingfactors, Muntz metal tubesheets are normally thick enough (nominally 1 to1.5 inches (2.5 to 3.8 cm)) to withstand the dezincification that occurs.However, in cases where galvanic-induced corrosion is significant, such as aMuntz metal tubesheet fitted with titanium tubes, dezincification hasoccurred at penetration rates exceeding 0.5 inches (1.3 cm) per year.

Many factors influence the dezincification of brasses. Drained condensers containing wet areascan undergo tube dezincification. This is because stagnant water at such sites has a reducedoxygen supply, which is conducive to attack. Wet areas under crevices or debris will increase thepossibility of dezincification. High chlorides, especially the levels found in brackish water orseawater, are another common cause. These waters are highly conductive and chlorides easilypenetrate the oxide layer.

Local pH suppression can have a great impact. Hydrolysis of copper salts on the metal surfacewill produce an acidic environment that will preferentially dissolve zinc. Porous deposits restrictthe access of oxygen (differential aeration) and sustain dezincification attack at the site. Scalecaused 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 alloyedwith 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 8-6Component 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


Failure Modes

8-14

Failure Prevention Practice – No practice is recommended as the thickness of the tubesheet orwaterbox is sufficient for the dealloying to occur over a forty-year life. If the dealloying iscoupled with galvanic corrosion, then cathodic protection or coating the tubesheet isrecommended. Control of dezincification of admiralty brasses has been achieved with materialchanges and water chemical treatment.

8.2.4 Erosion-Corrosion

Erosion-corrosion is a relatively common problem on the inside of copper-alloy tubes. It occursbecause of the effects of flow and does not occur when the cooling water is still. It is usually alocalized form of corrosion because it depends on the geometry of the system to direct the waterflow. 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 inthe direction of flow and are undercut on the downstream side. When the conditions becomesevere, it might result in a pattern of horseshoe-shaped grooves or pits with their open endspointing downstream. See Figure 8-3 for an example of inlet end erosion-corrosion.

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

Erosion-corrosion occurs because the flow-induced turbulence of the cooling water disrupts andremoves the protective oxide films from the surface of the copper-alloy tubes. Titanium andstainless steel-alloy tubes are not affected because their oxide films are quite stable in theturbulent flows typical of condensers.

Turbulence increases with increasing velocity and is greatly influenced by geometry. At tubeinlets, turbulence is more intense than several feet down the tubes. This results in thephenomenon known as inlet erosion-corrosion. If a tube becomes partially plugged with debrissuch as a mussel shell, a localized region of high velocity and turbulence can result around therestricted opening with the consequent occurrence of erosion-corrosion downstream of the


Failure Modes

8-15

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

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

Some suggested maximum velocities are shown in Table 8-7. While these velocities are forcondenser tube alloys in seawater, the data should also generally apply to other types of heatexchangers and other types of waters.

Table 8-7Suggested 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 orpollutants (for example, sulfides) in the cooling water.

Failure Prevention Practice – Measures for preventing erosion-corrosion in condenser tubesare:

x Substitute more resistant tube alloys

x Use inlet tube inserts

x Apply cathodic protection to inlet tubesheet


Failure Modes

8-16

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 ofthe tubesheets occurs when the tubesheet is coupled to electrochemically more noble tubes incooling water of sufficiently high conductivity. Due to a potential difference between dissimilarmetals, 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 thecombination of dissimilar tube and tubesheet materials, significant metal loss can occur in veryshort 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 condensercomponents, a cathodic protection system is sometimes installed to protect the more vulnerabletubesheets and waterboxes from galvanic corrosion. In such cases, tube manufacturers should beconsulted about the level of cathodic protection needed. Under certain circumstances, too high aprotection for tubesheets and waterboxes can be damaging to the tubes.

Key Technical Point

The primary factors affecting the magnitude of current flow and rate ofgalvanic corrosion are the potential differences between the metals, theenvironmental aspects of the electrolyte, the polarization behavior of therespective metals, and the relative areas of the coupled metal. Theenvironmental factors having the greatest effect in the galvanic corrosionrate are cooling water conductivity and temperature.

Galvanic corrosion rates will increase with an increase in cooling water conductivity andtemperature. Depending on material combination, chlorination of the cooling water can also havean important effect.

Table 8-8 lists galvanic potential differences of some materials that are commonly used incondensers, when the cooling medium is saltwater.


Failure Modes

8-17

Table 8-8Galvanic 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 andchlorinated water treatment is recommended.

8.2.6 General Surface Corrosion

General corrosion occurs on the inside of tubes, tubesheets, and waterboxes. This is also knownas tube wall thinning. It is characterized by relatively uniform metal loss due to corrosion alongthe entire length of the tube. Rates for titanium tube materials have been measured at 0.001mil/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 mitigatesome 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 commonoccurrence but hydrogen stress cracking and hydriding have been observed. Copper-alloy tubesare immune to this failure mechanism. Titanium and ferritic stainless steel tubes can incurdamage where cathodic protection is installed in the waterboxes.

For titanium tubes, the hydrogen generated by the passage of too high a cathodic protectioncurrent reacts with the metal to form a brittle titanium hydride phase in the microstructure. Forferritic stainless steel tubes, the passage of too high a cathodic protection current to the tubeservice can generate hydrogen at the surface. The hydrogen diffuses into the metal and can causestress cracking, especially near the tube ends. This is where roller expansion during installationresults in higher than normal residual stresses.

Failure Prevention Practice – The prevention measures include designing a cathodic protectionsystem to prevent polarization of tubes with a lower cathodic protection current or applyingprotective coatings to the tubesheet and waterbox.


Failure Modes

8-18

8.2.8 Random Pitting

Pitting is a form of localized corrosion that occurs on the inside of tubes, tubesheets andwaterboxes. 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 commonlyencountered condenser corrosion problem. Pitting is manifested mostfrequently 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 protectivefilm. Decaying organic matter left in the tubes during outages can generate sulfides. Also, pittingalong the bottom of the condenser tubes can be caused by sulfide-laden silt that often settlesthere. A sulfide concentration of as low as 0.01 ppm can be detrimental to copper alloys. Itshould 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 thatlay-up is the real cause of the problem. See Figure 8-5 for an example of pitting corrosion.

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

In addition, manganese can cause pitting damage to stainless steel tube materials. Manganesedioxide (MnO2) is a strong oxidizing agent that reacts with ferrous metals. MnO2 deposits thatphysically 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 corrosionrate resulting from increased cathodic current. For stainless steel, the electrochemical effects ofMnO2 deposition can promote pitting and crevice corrosion, causing rapid perforation of the tubewalls.


Failure Modes

8-19

Oxidizing biocides including halogens, peroxides, and ozone all have the capacity to oxidizedissolved manganese to MnO2. When halogens are used to control biofouling in waters thatcontain dissolved manganese, the resultant MnO2 and chloride create an aggressive environmentfor stainless steel. As a consequence, chlorination intended to control microbiologicallyinfluenced corrosion could promote corrosion failures in the system.

The established methods for removing MnO2 deposits are mechanical removal using scrapers orchemical cleaning. For more information on the manganese dependent corrosion in stainless steeltube 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, avoidstagnant lay-ups for long periods, flush during outages, prevent excessive biological fouling, andchemically 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 sideerosion manifests on the periphery of the tube bundle in areas under the exhaust flow sections ofthe turbine. In the early stages, the tube exhibits a polished appearance. As the attack continuesthe 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 waterdroplets 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 thefluid, the impact velocity, the mass flow per unit area, the hardness of thetube material, and the exposure time.

Failure Prevention Practice – The prevention measures are to use more resistant materials suchas stainless steel or titanium, use protector shields (protective jacket of stainless steel aroundperipheral 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 corrosiveenvironment. Copper alloys are susceptible to stress corrosion cracking in an ammoniaenvironment. See Figure 8-6 for a picture of stress corrosion cracking.


Failure Modes

8-20

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

Failure Prevention Practice – The prevention measures are to keep the oxygen level low, usestainless 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 observedat the tube mid-span between support plates. Fretting, characterized by formation of powderdeposits, is observed at the tube support points. Fatigue cracking is usually observed at mid-spanand sometimes occurs at support plates.

Condenser tubes also tend to vibrate under the influence of cross-flow velocities. Thesevelocities tend to be highest near exhaust trunks or steam dumps. High velocity results inexcessive 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. Smalleramplitude vibrations also cause fretting and fatigue damage at tube support points.

Key Technical Point

Flow-induced vibration damage occurs in condensers because the spacingbetween supports is too large or because the baffling at high-energy inletconnections does not provide adequate dispersion of the flow jet at theconnection.

The increasing use of thin wall tubing such as titanium or stainless steel makes destructivevibration even more likely. The low modulus of elasticity and the thin wall of a typical titaniumtube produce a greater deflection in vibration.


Failure Modes

8-21

Failure Prevention Practice – Preventive measures for vibration damage are to installadditional tube supports, stake the tube bundle around the periphery, install additional flow-dispersion 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 8-9Condenser Failure Mechanisms and Affected Components

Failure Mechanism Affected Component(s) Prevention PracticeCondensate CorrosionSection 8.2.1

Water side of tubes Reduce oxygen levels, use stainlesssteel or titanium tube material.

Crevice CorrosionSection 8.2.2

Water side of tubes,tubesheet

Seal weld joints, apply cathodicprotection or apply coating to thetubesheet.

DealloyingSection 8.2.3

Water side of tubesheet,waterbox

If galvanic corrosion, use cathodicprotection or use protective coatings.For dezincification, change materialsand use chemical treatment or applyprotective coatings.

Erosion-CorrosionSection 8.2.4

Water side of tubes Substitute resistant tube alloys, useinlet tube inserts, cathodicprotection, modifications for inletturbulence, clean tubes, reverseflow, apply coating to inlet tubes.

Galvanic CorrosionSection 8.2.5

Water side of tubesheet,waterbox

Cathodic protection, chlor-inated water treatment or applyprotective coatings.

General Surface CorrosionSection 8.2.6

Water side of tubes,tubesheet, waterbox

Cathodic protection or applyprotective coatings.

Hydrogen DamageSection 8.2.7

Water side of tubes Lower cathodic protection current orcoat the tubesheet and waterbox.

Random PittingSection 8.2.8

Water side of tubes,tubesheet, waterbox

Keep tubes clean, avoid stagnantlay-ups, flush during outages,prevent excessive biological fouling,and chemically treat water.

Steam Side ErosionSection 8.2.9

Steam side of tubes Substitute resistant tube alloys, useprotector shield and impingementbaffles.

Stress Corrosion CrackingSection 8.2.10

Steam side of tubes Keep oxygen level low, use stainlesssteel in air-removal sections, keeptubes clean.

Vibration DamageSection 8.2.11

Steam side of tubes Install additional tube support, stakethe tube bundle, install additionalflow-dispersion baffling, and reducevolumetric flow into the condenser.


Failure Modes

8-22

8.3 General Corrosion Prevention Practices [27]

Because of the prevalence of corrosion failure mechanisms on condenser components, it isimportant to prevent these mechanisms from damaging the condenser. These practices werereferred to in the previous section and are expanded in this section. The following are ten generalcorrosion 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 thisguide

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-tubesheet-induced galvanic corrosion of dissimilar waterbox materials, and general corrosion of thewaterbox.

Cathodic protection is a water side control method that arrests corrosion by creating an artificialenvironment. There are two types of cathodic protection systems:

x Sacrificial Anode Systems – The sacrificial anode cathodic protection system usessacrificial (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 usedmaterial.

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 andtubesheets are protected. Continued cathodic protection effectiveness is maintained byperiodic inspections of anode condition and replacement as required.


Failure Modes

8-23

x Impressed Current Systems – The impressed current cathodic protection system typicallyuses long-life or non-consumable anodes that are mounted through the waterbox walls. Adirect current rectifier is used to super-impose potential and current on the anodes andcondenser water side components. Sufficient potential current is provided to reverse thenatural potentials and currents associated with component corrosion, thus eliminatingcorrosion. 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 non-corrosive 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 maintenancepersonnel. If the system malfunctions, there is no cathodic protection.

x When the circulating water system is shut down, there is no cathodic protection. Coolingwater continues to drain from the tubes and corrosion can occur. For downtime situations ofseveral days or more, it is recommended that the tubes, tubesheets, and waterboxes beflushed with potable water. More discussion of lay-up recommendations is given inSection 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 galvaniccorrosion. Table 8-10 is for freshwater applications and Table 8-11 is for salt/brackish waterapplications.


Failure Modes

8-24

Table 8-10Freshwater Condenser Materials and Galvanic Corrosion Protection Applications [27]

Tube Material Tubesheet Material Waterbox Material Corrosion Protection

Muntz metal orAluminum bronze

Carbon steel Protective coating/cathodic protection ofwaterbox


Cast-iron None

Admiralty Brass

Carbon steel Carbon steel Protective coating onwaterbox andtubesheet, cathodicprotection of tubesheetand waterbox




Cast-iron None

90-10 Cu Ni

Carbon steel Carbon steel Protective coating onwaterbox andtubesheet, cathodicprotection of tubesheetand waterbox




Cast-iron None

304 SS

Carbon steel Carbon steel Protective coating onwaterbox and tubesheetcathodic protection oftubesheet and waterbox


Failure Modes

8-25

Table 8-10 (cont.)Freshwater Condenser Materials and Galvanic Corrosion Protection Applications [27]

Tube Material Tubesheet Material Waterbox Material Corrosion Protection

Solid titanium orcarbon steel clad withtitanium

Solid 316 or 317 SSor carbon steel cladwith 316 or 317 SS

None

316 or 317 SS 316 or 317 SS None


Cast-iron or carbonsteel

Protective coating/cathodic protection ofwaterbox

Copper alloy Cast-iron or carbonsteel

Protective coating/cathodic protection ofwaterbox

Titanium

Carbon steel Copper nickel Protective coating/cathodic protection ofwaterbox

Table 8-11Salt/Brackish Water Condenser Materials and Galvanic CorrosionProtection Applications [27]

Tube Material Tubesheet Material Waterbox Material Corrosion Protection316 or 317 SS 316 or 317 SS None316 or 317 SS Cast-iron or carbon

steelProtectivecoating/cathodicprotection of waterbox

Aluminum bronze Aluminum bronze Protectivecoating/cathodicprotection of waterboxand tubesheet

Aluminum bronze Cast-iron or carbonsteel

Protectivecoating/cathodicprotection of waterboxand tubesheet

Muntz metal Cast-iron or carbonsteel


Naval Brass Cast-iron or carbonsteel


Stainless steel

Silicon Bronze Cast-iron or carbonsteel



Failure Modes

8-26

Table 8-11 (cont.)Salt/Brackish Water Condenser Materials and Galvanic CorrosionProtection Applications [27]

Tube Material Tubesheet Material Waterbox Material Corrosion ProtectionStainless steel (cont.) Copper nickel Cast-iron or carbon

steelProtectivecoating/cathodicprotection of waterboxand tubesheet

Copper Alloys90-10 CuNi, 70-30CuNi, Aluminum brass

Copper alloy, Muntzmetal, Aluminumbronze, Naval brass,Silicon bronze,Copper nickel


Protectivecoating/cathodicprotection of waterbox


Solid 316 or 317 SSor carbon steel cladwith 316 or 317 SS

None




316 or 317 SS 316 or 317 SS None316 or 317 SS Cast-iron or carbon

steelProtectivecoating/cathodicprotection of waterbox

Aluminum bronze Aluminum bronze Protectivecoating/cathodicprotection of waterbox

Aluminum bronze Cast-iron or carbonsteel


Muntz metal Cast-iron or carbonsteel


Naval brass Cast-iron or carbonsteel


Silicon brass Cast-iron or carbonsteel


Titanium

Copper nickel Cast-iron or carbonsteel


8.3.2 Debris Filtration/Removal

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


Failure Modes

8-27

8.3.3 Proper Lay-Up

A major cause of condenser corrosion problems is the condition in which the condenser existsduring an outage. In most cases, the tube side is permitted to drain through the circulating waterpipe or through the waterbox drain line once the vacuum is broken. Condensers are seldomcleaned during short outages. During long outages, condensers might be cleaned at the end of theoutage if the schedule permits. Lay-up of a fouled condenser, especially one that is not vented,can be a source of potential corrosion.


Lay-up refers to all measures taken to prevent significant condensercorrosion during outages. Exposure of condenser parts to stagnant waterduring 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 ofcondensate. Circulating water, preferably containing biocides, should be pumped at leastonce a day for a minimum of thirty minutes. The purpose of this circulation is to relocate thesolids that might have settled on the tube surfaces and to limit the production of corrosivesubstances from decaying organic matter.

x Medium-term is defined as more than two days and up to two weeks. Condensate should becompletely drained from the shell side. Water side circulation should be continuous, or atleast one half-hour per day for wet lay-up. For dry lay-up, the waterboxes and tubes shouldbe completely drained and inspected visually. Any tube found plugged with debris should becleaned by shooting scrapers or brushes. After tube cleaning, waterbox, tubesheet, and tubeinternal surfaces should be flushed with potable water. This can be done quickly by using afire 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 allcondensate, as in the medium-term lay-up. All isolated pools of water should be dried byusing sponges or mops. Also consider circulating air through the shell with blowers. Airflowshould be monitored for temperature and humidity every few days and flow should beadjusted to achieve non-condensing conditions.

8.3.4 Design Modifications

Erosion-corrosion can occur in the waterbox, tubesheet, and inlet tube areas because ofturbulence in the inlet flow. Any modifications to the waterbox and tubesheet inlet might have tobe removed for tube cleaning. The addition of baffles and screens might influence any cathodicprotection that is installed.

Figure 8-7 shows a venturi effect from the inlet pipe being a smaller diameter than the inletnozzle.


Failure Modes

8-28

Figure 8-7Air 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) showsa perforated baffle plate as an improvement to this design.


Failure Modes

8-29

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


Failure Modes

8-30

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

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


Failure Modes

8-31

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


9-1

9 CONDITION-BASED MAINTENANCE [4,10]

A comprehensive condition-based maintenance program for a condenser consists of thefollowing 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 regardingthe condition of the condenser. These records should include a drawing of each tubesheetshowing the plugged tubes and the date of plugging. Each tube in the condenser should benumbered and all information recorded, including NDE testing results and failure analysis filedby the tube number.

9.2 Periodic Inspections

Visual examination of the water side of the condenser includes the waterboxes, tubesheets, andtube 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 thelocations in the tube bundle where corrosion is occurring. This might provide an indication of thecauses 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 theoriginal waterbox surface. Probing with a chisel will show the depth of the affected area. If thereis no reason to suspect only local occurrences of graphitization, a uniform corrosion over theentire surface should be assumed. Carbon steel waterboxes should be carefully inspected forsigns of galvanic corrosion.


Condition-Based Maintenance [4,10]

9-2

Waterbox inspections should be performed during each refueling outage and include thefollowing 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 cleaningintervals

x Inspection of the cathodic protection system for damage to anodes and supports; ensuringproper 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 refuelingoutage. 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. Observethe surface condition of the tube inlet. If deterioration is detected by touch, a photographicrecord is suggested. If scales are noticed on the tube outlet ends, bore measurements shouldbe recorded with a bore gage before and after cleaning.

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



9-3

9.2.3 Hotwell

Hotwell inspections should be performed during each refueling outage with the waterboxinspections. 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 overallcondition.

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 withthe 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 fromthe spargers.

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

x Support plate examination is usually limited to the periphery of the tube bundle. Distortionmight be apparent. If distortion is suspected, alignment should be checked by stretching astring through a set of holes. This will require extraction of a peripheral tube and subsequentplugging 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 eachrefueling 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 istypically a mild carbon steel plate. Use a wire brush, if required, to reveal cracks. NDE



9-4

methods can be used to confirm suspected cracks. The internal shell is also susceptible touniform 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-corrosionshould be recorded.

x Components such as flanges, channels, and pipe supports should be examined for distortionand 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 experiencesevere service conditions. Critical equipment is defined as equipment required for powerproduction. High duty cycle implies continuous operation and severe service conditions. Severeservice conditions include temperature cycling, water chemistry problems, tube vibration, andpoor quality of the cooling medium.

9.3.1 Cleaning

Key Technical Point

Cleaning by mechanical and/or chemical techniques is the only preventivetask that prevents corrosion or slows its progression, maintains tubereliability, and extends the life of the tubes.

If cleaning is not performed regularly as determined from plant experience, fouling and scalingadvance to the point where they become essentially unmanageable and physically difficult toremove. The recommended interval is as required because the appropriate schedule is verydependent on local conditions. The interval is less than two years for a significant fraction ofplants but might be longer in some cases.

Cleaning should include an evaluation of the type and degree of performance degradation andtype of fouling. The next step would be to determine the appropriate cleaning method thatprovides the best results and limits damage to the condenser materials including heat transfersurfaces, tubesheets, tube plugs, tube sleeves, waterbox, piping, and valves. The currentlyavailable options include mechanical devices (metal scrapers, plastic scrapers, and nylonbrushes), hydrolasing, chemical cleaning, and on-line cleaning (sponge ball systems and cageand 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 transferabilities, condenser backpressure, thermal efficiencies, and so on. More discussion on condenserperformance is found in Section 4.



9-5

Performance monitoring every week is recommended to address the vulnerability to suddenonset and propagation of corrosion and fouling. Performance monitoring should include thefollowing:

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 roundsmight include activities such as detecting external leaks, monitoring operational parameters suchas '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 inTable 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, weredeveloped and are listed in Table 9-2. The PM tasks include performance monitoring, NDEinspection, hotwell inspections, waterbox inspection, cleaning, and operator rounds.

NDE inspections include the use of eddy current testing, ultrasonic testing, and borescopeinspections. More details on NDE testing are given in Section 9.4.

Chemistry monitoring, chemical treatment, and cathodic protection are considered important butroutine activities in the operation and maintenance of the condenser.

EP

RI

Lic

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d M

ater

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on-B

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Mai

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[4,

10]

9-6

Tab

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ailu

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oca

tio

ns,

Deg

rad

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ech

anis

ms,

an

d P

M S

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Deg

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dat

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test

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tube

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, can

be

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EP

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[4,

10]

9-7

Tab

le 9

-1 (

con

t.)

Fai

lure

Lo

cati

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s, D

egra

dat

ion

Mec

han

ism

s, a

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Str

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ies

[10]

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Deg

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nM

ech

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dat

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Pro

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isco

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un

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tem

pera

ture

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Con

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ando

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scal

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mon

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curr

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g-L

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test

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as)

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Cor

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alva

nic

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mat

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oper

cat

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et m

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tinuo

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t to

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few

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try

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g-C

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test

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al tr

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spec

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g-W

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insp

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Def

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talla

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mR

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m-I

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spec

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re-L

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of a

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EP

RI

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Mai

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[4,

10]

9-8

Tab

le 9

-1 (

con

t.)

Fai

lure

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cati

on

s, D

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dat

ion

Mec

han

ism

s, a

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PM

Str

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un

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Mac

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, for

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mpl

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, fis

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arin

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and/

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m, d

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form

ance

mon

itorin

g-C

lean

ing

-Wat

erbo

xin

spec

tion

Sca

ling

orde

posi

t-S

and/

silt

-Im

prop

er c

hem

ical

trea

tmen

t-T

empe

ratu

re-L

ow fl

ow v

eloc

ity-E

nviro

nmen

tal

-Wat

er q

ualit

y-I

napp

ropr

iate

tube

clea

ning

-Con

tinuo

us

-Ran

dom

-Con

tinuo

us

-Ran

dom

, dep

ends

on c

ondi

tions

-Ran

dom

on

asc

ale

of 3

to 6

mon

ths

-Tur

bine

bac

kpre

ssur

e-'

P/'

T-I

nspe

ctio

n-C

lean

ing

-Hea

t tra

nsfe

r-C

hem

ical

trea

tmen

t

-Ope

rato

r ro

unds

-Per

form

ance

mon

itorin

g-C

lean

ing

-Wat

erbo

xin

spec

tion

Tu

bes

, co

nt.

Mec

hani

cal

dam

age

-Per

sonn

el e

rror

-Ran

dom

-Ran

dom

-Ins

pect

ion

-Hot

wel

l ins

pect

ion

Tu

be

Join

t-W

eld

edD

efec

t-I

mpr

oper

inst

alla

tion

-Im

prop

er p

lugg

ing

-Ran

dom

-Ran

dom

-Che

mis

try

mon

itorin

g-U

ltras

onic

leak

test

ing

-Pre

ssur

e te

stin

g

-Wat

erbo

xin

spec

tion

EP

RI

Lic

ense

d M

ater

ial

Con

diti

on-B

ased

Mai

nten

ance

[4,

10]

9-9

Tab

le 9

-1 (

con

t.)

Fai

lure

Lo

cati

on

s, D

egra

dat

ion

Mec

han

ism

s, a

nd

PM

Str

ateg

ies

[10]

Fai

lure

Lo

cati

on

Deg

rad

atio

nM

ech

anis

mD

egra

dat

ion

Infl

uen

ceD

egra

dat

ion

Pro

gre

ssio

nF

ailu

re T

imin

gD

isco

very

/Pre

ven

tio

nO

pp

ort

un

ity

PM

Str

ateg

y

Def

ect

-Im

prop

er c

lean

ing

tech

niqu

e-I

mpr

oper

inst

alla

tion

-Im

prop

er p

lugg

ing

-Ran

dom

-Ran

dom

-Che

mis

try

mon

itorin

g-U

ltras

onic

leak

test

ing

-Pre

ssur

e te

stin

g

-Wat

erbo

xin

spec

tion

Tu

be

Join

t-R

olle

d

Gal

vani

cat

tack

-Wat

er c

hem

istr

y-M

ater

ials

insp

ectio

n-I

mpr

oper

cat

hodi

cpr

otec

tion

-Con

tinuo

us-R

ando

m-I

nspe

ctio

n-C

atho

dic

prot

ectio

n-W

ater

box

insp

ectio

n

Wat

erb

ox,

Man

way

s,E

xpan

sio

nS

eals

, Wel

ds,

and

Lin

er

-Gen

eral

corr

osio

n-E

last

omer

agin

g/w

ear

-Mec

hani

cal

dam

age

tolin

er-F

aile

d w

elds

-Wat

er q

ualit

y

-Im

prop

er o

r fa

iled

cath

odic

pro

tect

ion

-Im

prop

erm

aint

enan

ce-A

ging

(el

asto

mer

)

-Con

tinuo

us

-Ran

dom

-Con

tinuo

us

-Exp

ect t

o be

failu

re-f

ree

for

man

y ye

ars

-Ran

dom

-Exp

ect t

o be

failu

re-f

ree

for

abou

t 5 y

ears

(dep

ends

on

usag

ean

d m

anuf

actu

rer)

-Ins

pect

ion

-Wat

erbo

xin

spec

tion

-Ope

rato

r ro

unds

Cor

rosi

on-I

mpr

oper

cat

hodi

cpr

otec

tion

-Wat

er c

hem

istr

y-M

ater

ials

-Con

tinuo

us-R

ando

m o

n a

scal

e of

mon

ths

toye

ars

-Cat

hodi

c pr

otec

tion

-Ins

pect

ion

-Wat

erbo

xin

spec

tion

Tu

bes

hee

t

Cra

ckin

g of

ligam

ents

-Im

prop

er p

lugg

ing

-Ran

dom

-Ran

dom

-Ins

pect

ion

-Wat

erbo

xin

spec

tion

EP

RI

Lic

ense

d M

ater

ial

Con

diti

on-B

ased

Mai

nten

ance

[4,

10]

9-10

Tab

le 9

-1 (

con

t.)

Fai

lure

Lo

cati

on

s, D

egra

dat

ion

Mec

han

ism

s, a

nd

PM

Str

ateg

ies

[10]

Fai

lure

Lo

cati

on

Deg

rad

atio

nM

ech

anis

mD

egra

dat

ion

Infl

uen

ceD

egra

dat

ion

Pro

gre

ssio

nF

ailu

re T

imin

gD

isco

very

/Pre

ven

tio

nO

pp

ort

un

ity

PM

Str

ateg

y

Hot

wel

l:E

xpan

sion

Join

t

Cra

cked

shie

ld p

late

Flo

w-in

duce

dvi

brat

ion

-Con

tinuo

usE

xpec

t to

befa

ilure

-fre

e fo

rse

vera

l yea

rs

-Ins

pect

ion

-Hot

wel

l ins

pect

ion

Ela

stom

erfa

ilure

, if

pres

ent

Agi

ng-C

ontin

uous

Exp

ect t

o be

failu

re-f

ree

for

seve

ral y

ears

-Ins

pect

ion

-Hot

wel

l ins

pect

ion

Def

ect

-Im

prop

er in

stal

latio

n-I

mpr

oper

plu

ggin

g-I

mpr

oper

cle

anin

g

-Ran

dom

-Ran

dom

-Che

mis

try

mon

itorin

g-P

ress

ure

test

-Ultr

ason

ic te

st

-Wat

erbo

xin

spec

tion

Hot

wel

l:P

enet

ratio

nB

affle

s an

dS

pray

Pip

es

Cra

ckin

g-M

anuf

actu

ring

defe

ct-V

ibra

tion

-Con

tinuo

us-R

ando

m-E

xpec

t to

befa

ilure

-fre

e fo

rm

any

year

s

-Ins

pect

ion

-Lea

k te

stin

g-T

urbi

ne b

ackp

ress

ure

-Air-

rem

oval

rat

e-A

ir bi

ndin

g

-Hot

wel

l ins

pect

ion

-Ope

rato

r ro

unds

-Cra

ckin

g of

wel

ds-V

ibra

tion

-Con

tinuo

us-E

xpec

t to

befa

ilure

-fre

e fo

rm

any

year

s

-Ins

pect

ion

-Hot

wel

l ins

pect

ion

Hot

wel

l:T

ube

Sup

port

Pla

tes,

Sup

port

Har

dwar

e,B

affle

Pla

tes,

Diff

user

Shi

elds

and

Fee

dwat

erH

eate

rS

uppo

rts

-Ste

amer

osio

n-D

esig

n de

fect

-Con

tinuo

us-E

xpec

t to

befa

ilure

-fre

e fo

rm

any

year

s

-Ins

pect

ion

-Hot

wel

l ins

pect

ion

Pen

etra

tion

Baf

fles

-Cra

ckin

g of

wel

ds-E

xces

sive

oper

atio

nal s

tres

s-D

esig

n de

fect

-Ran

dom

-Con

tinuo

us

-Ran

dom

, cou

ld b

era

pid

-Ins

pect

ion

-Che

mis

try

mon

itorin

g-H

otw

ell i

nspe

ctio

n

EP

RI

Lic

ense

d M

ater

ial

Con

diti

on-B

ased

Mai

nten

ance

[4,

10]

9-11

Tab

le 9

-2P

M T

asks

an

d T

hei

r D

egra

dat

ion

Mec

han

ism

s [1

0]

PM

Tas

kP

erfo

rman

ceM

on

ito

rin

gN

DE

Insp

ecti

on

Ho

twel

lIn

spec

tio

nW

ater

bo

xIn

spec

tio

nC

lean

ing

Op

erat

or

Ro

un

ds

Inte

rval

1 W

eek

2 Y

ears

2 Y

ears

2 Y

ears

As

Req

uir

edS

hif

tF

ailu

reL

oca

tio

nF

ailu

re T

imin

gD

egra

dat

ion

Mec

han

ism

Ran

dom

on

asc

ale

of m

onth

sto

yea

rs

Ero

sion

(inte

rnal

)X

XX

Ran

dom

, cou

ldbe

ver

y ra

pid

Ero

sion

(ext

erna

l)X

XX

Ran

dom

, cou

ldbe

ver

y ra

pid

Cor

rosi

on(M

IC)

XX

XX

Ran

dom

on

asc

ale

of w

eeks

to m

onth

s

Cor

rosi

on(C

hem

ical

)X

XX

Exp

ect t

o be

failu

re-f

ree

for

afe

w m

onth

s

Cor

rosi

on(G

alva

nic)

XX

X

Ran

dom

Def

ect

XX

Ran

dom

Cra

ckin

gX

XX

Ran

dom

on

asc

ale

of a

wee

kto

sev

eral

mon

ths

Mic

ro-

biol

ogic

alfo

ulin

g

XX

XX

Tu

bes

Ran

dom

, can

be

rapi

dM

acro

foul

ing

XX

XX

EP

RI

Lic

ense

d M

ater

ial

Con

diti

on-B

ased

Mai

nten

ance

[4,

10]

9-12

Tab

le 9

-2 (

con

t.)

PM

Tas

ks a

nd

Th

eir

Deg

rad

atio

n M

ech

anis

ms

[10]

PM

Tas

kP

erfo

rman

ceM

on

ito

rin

gN

DE

Insp

ecti

on

Ho

twel

lIn

spec

tio

nW

ater

bo

xIn

spec

tio

nC

lean

ing

Op

erat

or

Ro

un

ds

Inte

rval

1 W

eek

2 Y

ears

2 Y

ears

2 Y

ears

As

Req

uir

edS

hif

tF

ailu

reL

oca

tio

nF

ailu

re T

imin

gD

egra

dat

ion

Mec

han

ism

Tub

es, c

ont.

Ran

dom

, dep

ends

on c

ondi

tions

, can

be th

ree

to s

ixm

onth

s

Sca

ling

orde

posi

tX

XX

X

Tub

e O

DR

ando

mM

echa

nica

lda

mag

eX

Tub

e Jo

int:

Wel

ded

Ran

dom

Def

ect

X

Ran

dom

Gal

vani

cat

tack

XT

ube

Join

t:R

olle

dR

ando

mD

efec

tX

Wat

erbo

xM

anw

ay,

Exp

ansi

onS

eal,

Wel

dsan

d Li

ner

Exp

ect t

o be

failu

re-

free

for

abou

t fiv

eye

ars,

dep

ends

on

usag

e an

dm

anuf

actu

rer

Fai

led

wel

dsX

X

Exp

ect t

o be

failu

re-

free

for

man

y ye

ars

- C

orro

sion

- E

last

omer

agin

g

XX

Ran

dom

Mec

hani

cal

dam

age

tolin

er

XX

Ran

dom

, on

a sc

ale

of m

onth

s to

yea

rsC

orro

sion

XT

ubes

heet

Ran

dom

Cra

ckin

g of

ligam

ents

X

Hot

wel

l:E

xpan

sion

Join

t

Exp

ect t

o be

failu

re-

free

for

seve

ral

year

s

- C

rack

edsh

ield

pla

te-

Ela

stom

erfa

ilure

, if

pres

ent

X

EP

RI

Lic

ense

d M

ater

ial

Con

diti

on-B

ased

Mai

nten

ance

[4,

10]

9-13

Tab

le 9

-2 (

con

t.)

PM

Tas

ks a

nd

Th

eir

Deg

rad

atio

n M

ech

anis

ms

[10]

PM

Tas

kP

erfo

rman

ceM

on

ito

rin

gN

DE

Insp

ecti

on

Ho

twel

lIn

spec

tio

nW

ater

bo

xIn

spec

tio

nC

lean

ing

Op

erat

or

Ro

un

ds

Inte

rval

1 W

eek

2 Y

ears

2 Y

ears

2 Y

ears

As

Req

uir

edS

hif

tF

ailu

reL

oca

tio

nF

ailu

re T

imin

gD

egra

dat

ion

Mec

han

ism

Hot

wel

l:P

enet

ratio

nB

affle

s an

dS

pray

Pip

es

Exp

ect t

o be

failu

re-

free

for

man

y ye

ars,

som

e ra

ndom

Cra

ckin

gX

X

Hot

wel

l:T

ube

Sup

port

Pla

tes

and

Har

dwar

e,B

affle

Pla

tes,

Diff

user

Shi

elds

,F

eedw

ater

Hea

ter

Sup

port

s

Exp

ect t

o be

failu

re-

free

for

man

y ye

ars

- C

rack

ing

ofw

elds

;-

Ste

amer

osio

n

X

Pen

etra

tion

Baf

fles

Ran

dom

, cou

ld b

era

pid

Cra

ckin

g of

wel

dsX



9-14

9.4 Non-Destructive Examination (NDE) [4]

NDE consists of a large number of complex physical methods and procedures, designed toharmlessly test and evaluate the adequacy of a component, part, or a system. While NDEprocedures might or might not be non-invasive, they are always indirect assessments obtained bycorrelating the measured property with the reference standards.

NDE testing is primarily a material condition assessment and the information it provides ispredictive of future deterioration. It is beneficial to perform the task each outage to provide acontinuous assessment of condition. Substantial technical knowledge, skill, experience, andinformed judgment are essential for the successful application of NDE.

Among the NDE methods available, the following methods are classified as major ones for useon 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 testmethods is that it is fast and the surface need not be smooth and clean. This method is notapplicable to non-ferrous metals or alloys.

In this method, a magnetic flux is induced in ferromagnetic material. Any abrupt discontinuity inthe path of the flux creates local flux leakage. If finely divided particles of ferromagneticmaterial 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 applieddry 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 anopen surface flaw will absorb liquid colored dye by capillary action. Liquid dye is applied to asuspect surface and, after a soaking period of approximately 10 minutes, the surface isthoroughly cleaned and dried. A developer chemical is then lightly sprayed on the surface. Thedeveloper draws the dye out of the defect, clearly outlining the flaw. This method can be appliedto magnetic or non-magnetic materials. The tested surface must be thoroughly clean and smooth.



9-15

9.4.3 Ultrasonic Testing (UT)

This method employs high frequency mechanical vibration energy to detect structuraldiscontinuities and to measure the thickness of a variety of materials. Transmitted and reflectedsound energy is converted to electrical energy by a transducer. The signal received can bedisplayed on a cathode-ray tube to indicate conditions of the test object. UT can be used toidentify weld defects, cracks, and so on. Ultrasonic testing is used to measure the thickness oftubesheets for wear.

9.4.4 Eddy Current Testing (ET) [30]

Eddy current testing on condenser tubes can reduce maintenance costs by minimizing tube leaksand by establishing realistic plugging criteria. The availability of condensers is increased withET by extending the examination intervals and reducing the application of insurance plugs. Arealistic assessment of condenser condition can be provided by ET. This includes determiningthe number of degraded tubes, predicting the growth rate of current tube damage, and estimatingthe remaining operating life of the tube bundles.

ET is the technique used to locate or avoid future tube leaks. The technique allows adetermination of whether condenser tubes have become pitted, corroded, or cracked. It alsoprovides an estimate of the depth of such blemishes, their angular location and distance along thelength of the tube.

Key Technical Point

ET is a non-destructive test technique that causes electrical currents to beinduced in the material being tested. The associated magnetic fluxdistribution within the material is then observed. Because the results fromeddy current testing can be affected by a number of factors, successful eddycurrent testing requires a high level of operator training and awareness.

Eddy current testing is based on a correlation between electro-magnetic properties and physicalproperties of a test object. Eddy currents are induced in metals whenever they are brought into analternating current (AC) magnetic field. In test samples, eddy currents are generated by placingan AC coil in close proximity to the surface to be tested. These eddy currents create a secondarymagnetic field that opposes the inducing magnetic field of the coil, thus changing the coilimpedance. If a coil is drawn through a tube (Figure 9-1) or over a surface, the presence ofdiscontinuities will alter the eddy current and the coil impedance, identifying the location of thefault.



9-16

Figure 9-1ET Probe for Condenser Tube Testing [4]

ET is a surface and a volumetric testing technique for tubing. Penetration of eddy currents islimited by material conductivity and AC frequency. As depth increases, the penetration of eddycurrent decreases.

Key Technical Point

Eddy current instruments and recording instruments have a limitedfrequency response, that is, they require a certain time to respond to aninput signal. Therefore, pulling an ET probe through a tube at a high speedwill result in poor examination. Most testing should be performed at probespeeds 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. Bybringing the tubes to a clean state, the possible effects on the electromagneticflux distribution of any deposits present will be minimized.

Also, obstructed tubes should be cleared so that the ET probe can pass through. When startingwith 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 thesame tube material. Probes are usually either of the bobbin- or surface-type. For best results, theeffective diameter of the probe should be close to that of the inside diameter of the tube, withallowance being made for tube manufacturing tolerances.



9-17

The information obtained from ET conducted at several points in time can also help inscheduling maintenance and planning a tube replacement or plugging strategy. This is importantfor 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 mightbe 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 decisionwhether to plug the tube as a precaution against future leaks. The identification of near through-wall leaks will require tube plugging when all of the testing has been completed. Blocked tubesshould 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 andevaluation are also important parts of the overall project. In this way, the results of each test canbe compared and sound judgements can be made regarding the effects of different maintenancemethods, 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 orperiodic tests

x Insisting that the tests be conducted in exactly the same way for each inspection



9-18

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 andqualification requirements such as the ASME Boiler and Pressure Vessel Code, Section V,Appendix 8 - ASNT SNT-TC-1A


Where the bidding process might result in a different contractor beingemployed for each inspection, the necessity for a common procedure ensuresthat eddy current data from one inspection can be compared with confidenceto the data from inspections conducted in prior years. Without such formalprocedures and owner supervision, reliable data trending is virtuallyimpossible.

It might be said that firm adherence to established procedures tends to inhibit technologicaladvances. It is true that advances might be introduced more gradually. The absolute valuesobtained from eddy current testing are important in determining the damage mechanism and theappropriate corrective action to be taken. The ability to determine the rate of change of corrosionis 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 numberingshould be used for all future examinations and maintained throughout the life of the unit. Theconfiguration of this map should be well controlled and changes made only in a very orderlyfashion. Tubes that have been plugged should be clearly identified. At each inspection, thepreviously 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 shouldbe taken before the unit is first started up. This is a baseline for which future changes can becompared. The eddy current calibration tube should be taken from the same manufacturing batchas the tubes installed in the unit. The calibration standards should be stored in a known place andused 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, someusers 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 canbe analyzed independently. In the comparing mode, the data from several inspections should beable 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 plottingprogram can be separate from the analytical program, if it is written to accept the same data file



9-19

layout and format. The comparison of data sets, or trending, is made easier if 100% of the tubesare inspected every time. However, if only a subset of tubes is to be examined, this procedurerequires more careful planning to ensure a high level of data continuity from one inspection toanother.

9.4.4.5 Maintenance Practices

In order that changes in corrosion rate be correlated with procedural changes, it is important tolog all changes in maintenance practice as they occur. For example, at one site, mechanicalcleaning was identified as the cause of the reduced corrosion rate. Changes in water treatmentpractice should also be logged, and a summary of all of these changes provided to the inspectorbefore a new eddy current inspection is performed.

9.4.4.6 Figures of Merit


The term figures of merit as used in the analysis of eddy current tests is thegeneric name applied to various criteria used to compare test results. Figuresof merit have different criteria in the case of a condenser compared withthose for a heat exchanger. With heat exchangers, considerations of meetingthe Pressure Vessel Code override questions of mere wall penetration. In anygiven plant, there should be some agreement on how corrosion figures ofmerit 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 haveused this to predict when a condenser should be retubed. Figures of merit can also be used astube plugging criteria although, as the number of plugged tubes increases, the reduced capacityof 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 isdifficult 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 canunderstand 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 tobe completed for the planning phase of the process:

1. Gather condenser design, operating, chemistry, and prior ET exam data. Any abnormaloperating history, chemistry incursions, known problems, etc. should be reviewed. Obtainingthe last set of ET results is needed for comparison.



9-20

2. Establish the tube-sampling scheme consistent with the existing numbering system. Animportant consideration for selecting an inspection sample is the expected or known damagemechanisms based on past inspection results or repair records. This generally includestargeting those tubes with degraded indications and tubes surrounding the already plugged orleaking tubes. It is also desirable to include a sample of tubes for detection of any newproblems. The selected percentage varies but typically will be in the range of 10-30%. Thecombined sampling scheme of targeted and random sampling should equal around 40% ofthe 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 thesurrounding tubes no longer exhibit degraded flaw conditions.

3. Establish tube plugging criteria – The current plugging criteria for condensers varies fromplant to plant and is based on percent wall losses, that is, 40 to 80% wall losses. The tubeplugging criteria in percent wall loss is equated to allowable wall loss minus eddy currentsizing error.

Currently, the allowable wall loss in percent wall loss is derived from the following weightedaverage 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 therange of 50-90 percent wall loss. Consequently, if the eddy current sizingerror of 10 percent is used, the resultant plugging criteria can be 40-80percent 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



9-21

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 finalrecommendations to management.

9.4.4.11 ET Flowchart

Figure 9-2 shows the important features of an effective eddy current condenser inspectionprocess in a flowchart format.



9-22

Figure 9-2ET Flowchart [30]


10-1

10 MAINTENANCE REPAIRS [3]

There are numerous repairs that might be necessary to perform on condensers. Some of the typesof repairs are:

x Plugging tubes

x Installation of tube inserts or shields to protect the tube inlet/outlet from erosion/corrosion orto 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 fordecades to provide temporary plugging/stopping of a small leak or leaks. The leak stop materialis dumped into the intake bays immediately upstream of the circulating water pumps. Sawdust inthe circulating water flow fills and lodges in condenser tube holes temporarily preventingleakage. Sawdust is continuously injected into the system until the hotwell cation conductivityreading returns to normal. When the leak stops, the need for hotwell blowdown/makeup and/oruse of the condensate polishing demineralizers will significantly reduce. A subsequent rise incation 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 necessityto perform a condition assessment and life prediction analysis. Once sawdust is used, it is certain


Maintenance Repairs [3]

10-2

that chronic tube leaks will persist and ultimately will become so severe that sawdust injectionwill become an ineffective control agent. The tube failure rate at that time will become verysignificant, 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 typicallyexcess surface area in the condenser design to allow as many as 10% of the tubes to be pluggedwithout reducing the effective heat transfer capacity of the unit. Plugging is also performed fromeddy 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 fora specific plug design. Numerous plugging methods are available depending on the tube materialand 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 pluggingtubes:

1. The tubes to be plugged should be located and clearly identified. Both ends of the same tubeshould be clearly marked. A common problem observed during leak testing is the marking ofthe leaking tube on one tubesheet and incorrectly marking the tube on the other end of thetubesheet. Several ways to ensure that both ends of the same leaking tube are markedcorrectly 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 plugand 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-heatand post-weld stress relieving. Warping of the tubesheet and damage to adjacent tube jointscan occur if the proper stress relieving is not performed.

5. If necessary, stabilize the failed tube to prevent additional damage to neighboring tubes. Thiscan be accomplished by inserting a rod or cable into the tube to provide additional internalsupport. The rod or cable should be long enough to bridge the defective region of the tubeand reach through the next support plate. One end of the stabilizer should be anchored to thetube and/or tubesheet to prevent migration within the tube during condenser operation. Tubestabilizers can be fabricated on site or purchased commercially. Unless the stabilizer is anintegral part of one of the tube plugs, both ends of the tube should be plugged after installingthe stabilizer.

6. After the plugging operation, leak testing of the plugged tubes is recommended.



10-3

10.1.2 Tube Plug Selection [3]

There are many different types of condenser tube plugs from which to choose. Consider thefollowing 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 plugshould not damage the tube, tubesheet ligaments, tube joints, or the epoxy coating applied tothe tubesheet and/or tube.

x The plug itself should be constructed of materials that are rated for an infinite life ofcontinuous duty in the condenser environment. The plug materials should resist anycorrosion and aging effects that might cause leakage.

x The ideal condenser plug should not require periodic re-tightening and inspection to verifythat 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 havecaused collateral damage to the tube and tubesheet, the actual plug costshould not be a major factor. The expense associated with controllingpersistent water in-leakage as a result of tube and plug leaks can be manytimes 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 ahammer. These plugs are easily fabricated on site or are available from a number of commercialsources. Plug materials include wood, plant fiber and metal alloys. Consideration should begiven 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 makesa good fit when driven into the tube with a hammer. The plug swells when wet and the swellingmakes a tight fit. Some examples of tapered plugs are shown in Figure 10-1.



10-4

Figure 10-1Assorted 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 aninterference fit between the plug and the tube end and also the tube end and the tubesheet. Theintention 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 ortubesheet.

x These plugs are difficult to remove for tube replacement. Some hammer-in taper plugs aremanufactured with a drilled and tapered hole on the large diameter end to improveremovability.

x These plugs have low seal integrity.

Two-piece hammer-in plugs employ a conical-shaped pin that fits into an outer sealing ring. Anexample of this style plug is shown in Figure 10-2.



10-5

Figure 10-2Two-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 thering so that the ring expands outward to seal against the tube wall. The greater surface area of thering distributes the installation forces over a greater area of the tube, thereby reducing collateraldamage to the tube, tube joint, and tubesheet. Two-piece hammer-in plugs are commerciallyavailable in a number of metal alloy materials. Consideration should be given to plug materialselection in order to prevent galvanic corrosion. When this plug is properly installed it provides amoderate 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 defectscaused 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 ortubesheets.

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. Onedesign is shown in Figure 10-3.



10-6

Figure 10-3Elastomer Plug (courtesy of Conco Systems, Inc.)

The plugs use an elastomer element or elements that are squeezed or expanded outward againstthe tube wall to form a seal. Most elastomer plug designs employ a mandrel to support one ormore expandable elastomer seals. Tightening a nut or threaded member on the mandrelcompresses the seal(s) along the mandrel. This causes the seal to expand radially outward intocontact with the tube wall. Installation forces are established using either a prescribed number ofturns or a prescribed torque value.

A simpler push-pull elastomer-type plug design is also available. The push-pull plug is stretchedduring installation. This action causes the plug diameter to shrink and allows the plug to slip intothe tube end. This plug type seals as the installation load is released and the plug relaxes/expandsto its original size. Figure 10-4 shows an example of how one elastomer plug design works.



10-7

Figure 10-4Elastomer Condenser Plug Diagram (courtesy of Torq N Seal™ )

Plugs with elastomer seals alone can provide working pressures to 500 psi (3.4 megapascals) andabove. Plugs in this class are commercially available in a number of different elastomercompounds with mandrels and compression hardware available in materials ranging from



10-8

engineered plastics to metal alloys. Consideration should be given to operating temperatures andgalvanic corrosion when selecting the tube plug materials.

Other types of elastomer plug designs incorporate an integral set of expandable metallic grippingsegments along with the elastomer seal(s). The grips allow higher operating pressures. Elastomerplugs 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 holdthe plug in place.

An example of this design is shown in Figures 10-5 and 10-6. These figures show an elastomerplug with an o-ring in the shelf and installed conditions. These plugs consist of a chloropreneexpanding cylinder. An elastomer o-ring provides a positive seal. The plug is installed bytightening the bolt at the end to the specified torque. Various manufacturers specify the testpressure for their plug from 500 to 5000 psi (3.4 to 34.5 megapascal).

Figure 10-5Mechanical Gripper-Type Plug, Shelf Condition (courtesy of Powerfect, NJ)

Figure 10-6Mechanical Gripper-Type Plug, Installed (courtesy of Powerfect, NJ)



10-9

Limitations for elastomer plugs include the following:

x The elastomer materials are subject to compression set and age hardening in the hot, wetconditions found in the condenser.

x Over time, the elastomer materials lose their compressibility and become susceptible toleakage, vibration, and plug loss.

x Elastomer plugs are generally acknowledged to have a limited service life. A program ofperiodic inspection, tightening, and possibly plug replacement should be incorporated intothe 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 scheduledoutage.

10.1.3.3 Mechanical Plug

Mechanical plugs are metal plugs that come in several styles. The breakaway plug uses aconical-shaped tapered pin that is drawn axially through an expandable metallic sealing ring. Anexample is shown in Figure 10-7.

Figure 10-7Mechanical 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 tubewall defects and tube roundness. The plug is installed using a compact hydraulic ram or manualplug installation tool. This plug type is initially smaller than the tube inside diameter and mightbe recessed into the tube end for installation. This style plug can also be used to plug a tubesheethole. This style plug should not damage the tube or tubesheet coatings. Consideration should begiven for proper plug material selection. These style plugs provide a high degree of seal integrityand are easily removable.

Another type of mechanical plug is the thimble-style plug. This plug is a thin-walled, thimble-shaped metallic plug that is expanded into the tube or tubesheet hole. Mechanical rollerexpanders or hydraulic expansion methods are used for installation. Care should be exercisedwhen installing this plug to not over-expand the plug. This can result in tube joint failure of



10-10

adjacent tubes. Generally, a fiber hammer-in taper plug is driven into the open end of the thimbleafter it has been expanded. This is to identify the tube that is plugged. Consideration should begiven 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 installingthe hammer-in plug to prevent damage to adjacent tubes. When properly installed, this style plugprovides a high degree of seal integrity and can be removed using conventional tube pullingtechniques. An example of a thimble-style plug is shown in Figure 10-8.

Figure 10-8Thimble-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 isdriven into the tube end or tubesheet hole. The plug is then seal-welded to the tube, tubesheetcladding, and/or tubesheet base material. Welded tube plugs must be compatible with thematerials to which they are welded. Caution is needed when driving in the plug prior to weldingto prevent cracking the tube and/or tubesheet. Adequate pre-heat and post-weld stress relievingprocedures should be followed to prevent weld failure, warping of the tubesheet, and damage toadjacent tube joints. When properly installed, these plugs offer high working pressures and ahigh 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, andthe wet conditions in the waterbox.

x Welded tube plugs are difficult to remove.



10-11

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 AppendixC. These procedures are the current ones given by the manufacturer and can change. It is a goodidea to consult the most recent set of installation instructions from the vendor before installingthe plug.

EP

RI

Lic

ense

d M

ater

ial

Mai

nten

ance

Rep

airs

[3]

10-1

2

Tab

le 1

0-1

Tu

be

Plu

g D

ata

Man

ufa

ctu

rer

Typ

e o

f P

lug

Co

mp

osi

tio

nC

har

acte

rist

ics

Atla

ntic

Gro

upw

ww

.atla

ntic

grp.

com

Bra

ss a

nd fi

ber

jack

eted

Bra

ss p

lug

with

a fi

ber

jack

etW

ater

or

stea

m a

pplic

atio

n on

ly, m

axim

umte

mpe

ratu

re is

350

°F

(17

7°C

)B

emar

k A

ssoc

iate

s, In

c.1-

302-

234-

7587

K-S

pan

Plu

gB

rass

, car

bon

stee

l, st

ainl

ess

stee

l, or

titan

ium

Siz

es fo

r 5/

8 in

-1

1/4

in (

14 -

32

mm

) tu

be,

expa

nsiv

e ra

nge

is 0

.040

in (

1 m

m),

up

to80

0 ps

i (5.

5 m

egap

asca

l), u

p to

400

°F(2

04°C

), fo

r tu

be o

r tu

besh

eet p

lugg

ing.

Hig

h co

nfid

ence

tube

plu

gC

hlor

opre

ne a

nd b

rass

, bro

nze,

stai

nles

s st

eel,

or ti

tani

umS

izes

for

3/4

in -

1 1

/4 in

. (19

- 3

2 m

m)

tube

,se

als

up to

500

psi

(3.

4 m

egap

asca

l). C

anbe

use

d on

coa

ted

tube

shee

ts. P

lug

has

mac

hine

d se

rrat

ed a

djus

tabl

e gr

ippe

rs.

Exp

andi

ng tu

be p

lug

EX

-3C

hlor

opre

ne a

nd b

rass

, bro

nze,

stai

nles

s st

eel,

or ti

tani

umS

izes

for

5/8

in -

1 1

/4 in

(14

- 3

2 m

m)

tube

,la

rge

outs

ide

was

her

on o

ne e

nd a

llow

s pl

ugto

fit f

lush

with

tube

shee

t and

not

be

pulle

din

to tu

be b

y va

cuum

, tes

ted

to 3

75 p

si(2

.6 m

egap

asca

l).E

xpan

ding

tube

plu

g E

X-4

Chl

orop

rene

and

bra

ss, b

ronz

e,st

ainl

ess

stee

l, or

tita

nium

Siz

es fo

r 5/

8 in

- 1

1/4

in (

14 -

32

mm

) tu

be.

Equ

al-s

ize

was

hers

allo

w p

lug

to b

epo

sitio

ned

in tu

be b

eyon

d flu

sh o

f tub

eshe

et.

Tes

ted

to 3

70 p

si (

2.5

meg

apas

cal).

Con

co S

yste

ms,

Inc.

ww

w.c

onco

syst

ems.

com

Exp

andi

ng tu

be p

lug

EX

-FC

hlor

opre

ne a

nd v

ulca

nize

d fib

er a

ndbr

ass,

bro

nze,

sta

inle

ss s

teel

or

titan

ium

Siz

es fo

r 5/

8 -

1 1/

4 in

(14

- 3

2 m

m)

tube

.C

hlor

opre

ne e

xpan

ds a

nd s

eals

whe

ntig

hten

ed. V

ulca

nize

d fib

er e

xpan

ds w

hen

wet

for

grip

ping

act

ion.

EP

RI

Lic

ense

d M

ater

ial

Mai

nten

ance

Rep

airs

[3]

10-1

3

Tab

le 1

0-1

(co

nt.

)T

ub

e P

lug

Dat

a

Man

ufa

ctu

rer

Typ

e o

f P

lug

Co

mp

osi

tio

nC

har

acte

rist

ics

Pin

plu

gV

ulca

nize

d fib

erS

izes

for

5/8

- 1

1/4

in (

14-3

2 m

m)

tube

.V

ulca

nize

d fib

er’s

hyd

rosc

opic

act

ion

expa

nds

whe

n w

et.

Pin

plu

g ty

pe 1

Bra

ss, b

ronz

e, s

tain

less

ste

el, o

rtit

aniu

mS

izes

for

5/8

- 1

1/4

in (

14-3

2 m

m)

tube

.O

ne-p

iece

plu

g fo

r te

mpo

rary

or

perm

anen

ttu

be p

lugg

ing.

Con

co S

yste

ms,

Inc.

(con

td.)

ww

w.c

onco

syst

ems.

com

Pin

and

col

lar

Bra

ss, b

ronz

e, s

tain

less

ste

el, o

rtit

aniu

mS

izes

for

5/8

- 1

1/4

in (

14-3

2 m

m)

tube

.T

wo-

piec

e pl

ug fo

r te

mpo

rary

or

perm

anen

ttu

be o

r tu

besh

eet p

lugg

ing.

Vib

raP

roof

con

dens

erpl

ug/e

xpan

dabl

e el

asto

mer

plug

Neo

pren

e, s

ilico

ne o

r V

iton™

elas

tom

er s

eals

with

bra

ss, b

ronz

e,st

ainl

ess

stee

l, or

tita

nium

har

dwar

ean

d lo

cknu

t. O

ther

mat

eria

lco

mbi

natio

ns a

vaila

ble

on r

eque

st.

(Vito

n is

a r

egis

tere

d tr

adem

ark

ofD

uPon

t Dow

Ela

stom

ers.

)

Plu

g si

zes

avai

labl

e to

fit 3

/8 in

to 1

1/4

in(9

.5-3

2 m

m)

tube

s. C

an b

e us

ed in

coa

ted

tube

s an

d tu

besh

eets

. Lar

ge p

ositi

onin

gw

ashe

r re

sist

s va

cuum

. Ope

ratin

g pr

essu

res

to 1

50 p

si (

1 m

egap

asca

l).

Exp

ansi

on S

eal

Tec

hnol

ogie

sw

ww

.exp

ansi

onse

al.c

om

Per

ma

plug

con

dens

erpl

ug/e

xpan

dabl

e m

etal

plug

Bra

ss, c

arbo

n st

eel,

stai

nles

s st

eel,

copp

er n

icke

l, an

d tit

aniu

m a

lloys

stan

dard

. Oth

er a

lloys

ava

ilabl

e on

requ

est.

Plu

g si

zes

avai

labl

e to

fit t

ube

and

tube

hol

eID

s fr

om 0

.491

in to

1.3

36 in

(12

.5-3

3.9

mm

).In

stal

ls in

sec

onds

. Hel

ium

leak

-tig

ht to

1 x

10-1

0 cc

/sec

. Con

serv

ativ

ely

rate

d in

cond

ense

r se

rvic

e fo

r op

erat

ing

pres

sure

s in

exce

ss o

f 300

psi

(2

meg

apas

cal).

Will

not

dam

age

coat

ed tu

bes

and

/ or

tube

shee

ts.

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10-15

10.1.4 Tube Plug Removal

It is necessary to remove a tube plug that is leaking. Also, prior to any tubesheet repairs orcondenser retubing, the tube plugs must be removed. The following is a discussion of tuberemoval 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 shouldbe used:

1. Drive a 12 point socket into the exposed end of the plug. Install a socket wrench or breakerbar 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 opposingsides 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 totwist and loosen the plug.

4. Use a center punch to mark the exposed end of the plug. Drill and tap the plug to allowattachment of a slide hammer, tube spear or plug removal tool. The slide hammer/tube pulleris operated until the plug is pulled from the tube end. A typical plug removal tool is acombination slide hammer and tube spear. An example of a tube-pulling tool is shown inFigure 10-9.

Figure 10-9Plug Removal Tool (courtesy of Expansion Seal Technologies)

In situations where the plug is flush with or recessed within the tube end, the followingtechniques should be considered.



10-16

x Mark the exposed end of the plug with a center punch. Drill and tap the plug to allowattachment of a slide hammer, tube puller, or plug removal tool. Operate the slide hammer ortube 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 theplug.

For the two-piece hammer-in plugs, the tapered pin or entire plug assembly can be removedusing any of the techniques outlined above. If the pin is removed, leaving the ring within the tubeend, 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 aslide hammer or tube puller to the spear. Operate the puller or slide hammer to withdraw thering from the tube end.

x Using the bore of the ring as a drill guide, drill through the ring with successively larger drillbits until the ring can be withdrawn from the tube end. Exercise caution during drilling toprevent the drill from moving off center or drilling at an angle. Damage to the tube ortubesheet could occur that will make re-plugging difficult.

x Use successively larger, stiff bristle, metal brushes to wear away the ring material from theinside 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 mightslide out of the tube end. If the plug is stuck within the tube, pry the plug loose using a clawhammer or tube pulling device. Exercise caution to prevent damage to adjacent tube ends duringthe removal process.

10.1.4.3 Mechanical Plugs

For the mechanical plugs, remove any remaining portion of the plug from the exposed end of thepin. Thread a plug removal tool into the tapered pin. Use the slide hammer to drive the conicalpin back through the ring into the tube. Thread the tapered spear into the ring and operate theslide 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 plugbody. Attach a slide hammer or hydraulic tube puller and operate the tool until the plug is pulledfrom 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. Theexposed end of the plug should be marked with a center punch, drilled, and tapped to allowattachment of a slide hammer, tube puller, or plug removal tool. Operate the tool until the plug ispulled from the tube end.



10-17

10.2 Tube Inserts [3]

Using tube inserts to solve the problem of leaking tubes requires advance planning for orderingand installing the insert. A common practice is to use flared or flanged plastic inserts or tubeprotectors designed to alleviate the inlet end erosion. Polymeric inserts are designed to fit snuglywhen installed in the affected tubes. The insert tube interference fit becomes more pronouncedafter a period of time because the polymers used are designed to swell by water absorption uponexposure. Non-water-absorptive polymeric inserts (such as nylon) are typically secured inposition with adhesive sealants. Non-metallic inserts do not cause galvanic corrosion of tubes ortubesheets. 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 thesponge ball cleaning system.

x Eddy current testing of the tubes is more problematic because of the narrowing of the tubeinside diameter for the length of the insert and at the step from the insert to the original tubediameter.

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-steperosion further along the tube and thus introduce a different kind of problem. See Figure10-10 for a tube insert.

Figure 10-10Tube Insert [24]

As an alternative, the use of metallic, thin-walled inserts or shields, provides a more durablesolution. Metal alloy inserts are six- to eight-inch (15 to 20 cm) long thin wall tubes that have anoutside diameter slightly less than the inside diameter of the tubes to be restored. First introducedin 1976, these shields are made with a chamfered outlet end. This greatly reduces the chance of



10-18

end-step erosion. They are also hydraulically expanded into the host tube. This structurallyreinforces 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 differentinsert 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 afraction of that associated with plastic tube inserts.

An improved insert is shown in Figure 10-11.

Figure 10-11Improved 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 interfacebetween the tube and tube insert where sludge tends to accumulate

Key Technical Point

Corrosion-resistant insert materials typically specified are: AL-6X, AL-6XN, 70-30, 85-15 or 90-10 Cu-Ni and 304 or 316 Stainless Steel. AL-6X isthe most widely used insert material.



10-19

While appropriately specified and installed inserts eliminate condenser tube inlet end erosion-corrosion, highly corrosion-resistant inserts can create new corrosion problems, often as seriousor more serious than the original event causing the need for the use of the inserts. The majorinsert-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 theinsert 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 insertinterface

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 canbe installed to bridge across the degraded area. The length of the sleeve is limited to the workingspace inside the waterbox, assuming the waterbox cover is not removed. Either roller expansionor hydraulic expansion can be used to create the sealing joint between the sleeve and the originaltube. The material used for sleeving is metallic and compatible to the tube being repaired. Atypical sleeve installation configuration is shown in Figure 10-12.



10-20

Figure 10-12Sleeve Repair (courtesy of Framatome Technology)

10.4 Tube End Coatings [3]

Key Technical Point

An alternative approach to tube inserts for tube end erosion/corrosionproblems is to apply a tube end epoxy coating that can halt the erosionprocess. The coatings are applied in multiple coats for a total coatingthickness of 9 to 10 mils (229 to 254 µm). The coatings are applied into thetube end to the required depth, usually between 2 and 30 inches (5 and76 cm), depending on the width of the waterbox. The metallurgy of the tubeto be coated is not significant because the coating is compatible with all tubematerials.

Such coatings have been used in service and cooling water system applications for over 15 yearsand have also been successfully used with both freshwater and seawater environments. Each coatin the tube conforms to the tube wall and extends beyond the previous coat, so that a feathered



10-21

termination surface is achieved. This eliminates the possibility of step erosion occurring in thearea where the coating terminates.

The work is usually performed during an outage and the application of the coating is completedwith the waterbox in place. It is highly recommended that throughout the application process, allenvironmental control equipment, such as dehumidification and dust collection systems, beplaced 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 andmost off-line tube cleaning methods. With metal scrapers, plastic nozzles must be used on thecleaning 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 accidentallyremove the coatings.

When tube end coatings are selected as the method for repairing tubes, such coatings are usuallyapplied 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 thebest solution. Because the tubesheet coating is 9 to 10 mils (229 to 254µm) in thickness, it isdifficult to bridge over through-wall penetrations. Surface preparation and quality control of theanchor pattern along the tube length are key factors in the success of the application. Thedifficulties are greater with longer tube lengths.

Tube end coatings are most beneficial for erosion/corrosion and pitted tube ends that are inservice. If a tube has been identified as having a through-wall penetration, an insert has a betterchance 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 canalso 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 toseal the tube. The liner is then filled with water, the air is bled out, and a hydro-expansion pumpis used to expand the liner to achieve an almost completely metal-to-metal fit. After remainingpressurized for a short time, the pressure is released and the water is drained out. Then the endsof the expanded liner are cut off and milled flush to the tubesheet. The tube ends are then roller-expanded 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 full-length liners do have a greater impact. Because the thickness of the liner is small, anydegradation in the overall heat transfer coefficient is due to the metal-to-metal contact achievedbetween the liner and the tube during the expansion process.



10-22


Tubes in service have defects. These defects or indentations can result frominstallation or in-service conditions. The liner might not be able to overcomeall tube inside diameter defects and, thus, will not be expanded to meet thetube inside diameter by hydro-expansion. The defects create air pockets thatcan significantly retard heat transfer. Because of the uncertainty of theapplication results, it is recommended that heat transfer studies beconducted on several samples of the tubes to be lined. In this way, the effecton heat transfer can be established prior to the relining process beingimplemented 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. Itwas introduced to protect tubing material from inside diameter pitting, from full-length tube wallthinning, and/or to prevent copper ions from being leached from condenser tubing directly intothe circulating water.


The full-length tube coating material is applied with an average thickness of2–4 mils (51–102 µm). However, the actual coating thickness selected has tobe balanced between solving a particular problem and retaining sufficienttube heat transfer capability.

Proper tube surface preparation can include washing with high-pressure water, mechanicalcleaning, and abrasive blasting. The coating material is then applied using automated sprayingequipment. Again, it is highly recommended that throughout the application process, allenvironmental control equipment, such as dehumidification and dust collection systems, beplaced in full operation.

In the early 1990s, a U.S. utility decided to coat tubes to prevent copper ion release fromcondenser tubes and the subsequent discharge of the ions with the circulating water into a coastalsaltwater inlet. The concern was a violation of an EPA upper limit on allowable copperconcentration in discharges into pristine water. This problem was solved successfully by applyinga 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-wallpenetrations, other considerations must be reviewed. Because gravity causes the coating to bethicker toward the bottom of the tube, tube penetrations located toward the top of the tubecircumference might not be sealed adequately. Surface preparation and quality assurance alongthe whole length of the tube is a key factor in the success of the application. The difficulties aregreater with the longer lengths of tubes. Consequently, the epoxy coating of the internal surfacesof tubes should be approached with caution if the purpose is to eliminate leaks through tube wallpenetrations. Also, impressed current cathodic protection systems can cause damage to the full-length coatings.



10-23

In the evaluation of full-length tube coatings, the issue of cathodic protection on the tubesheetshould 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 downtimeexperienced during retubing

x Extend the life of condensers on older units whose remaining life is less than the life of aretubed condenser and at a lower cost

x Limit copper levels discharged from tubes in routine operation to those allowed under newEPA or regulatory agency limits

x Extend the life of tubes in one waterbox to correspond with the remainder of the unit’swaterbox tubes end-of-life or to meet budget and /or outage restraints

The first generation of coatings included the Metal Modified Siloxirane by Corrodex, theModified Epoxy 600 EP by Plastocor, the Polyamine Epoxy by Keeler and Long and the TeflonModified Epoxy Phenol by Corrodex. The second generation of coatings included an epoxyphenolic by Corrodex, the modified Siloxirane by Corrodex, a German epoxy, a urethane epoxyfrom Europe, and a modified epoxy from the United States. Additional coatings tested includereformulated Keeler and Long’s Polyamine epoxy No. 3250 V and Plasite 7156.

In the testing done at Florida Power Corporation, dry sandblasting techniques successfullyprepared tubes for coating. A cleaning lance, made of steel pipe fitted with a tungsten carbidecone-shaped spray nozzle, blasted clean 1,280 tubes per day using black beauty grits. A newlydeveloped coating application system consisted of a diaphragm pump, fluid pressure regulator,patented spray nozzle and hoses, and an automated feeding and retrieving device. This systemproved 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 theFlorida Power Corporation’s Bartow #2 condenser showed that coated tubes remained cleanerfor longer periods of time than uncoated tubes. Subsequent reductions in the frequency of tubecleanings resulted in labor savings. Tested after more than three years in service, the Bartow #2coated condenser tubes offered more efficient heat transfer performance than uncoated tubes inthe unit. Furthermore, the coated tubes showed no sign of deterioration after four years ofservice.

Tests conducted on the Bartow #2 condenser tubes clearly indicate that properly prepared andcoated tubes can perform with no negative effect on unit heat rate. However, if an impropercoating is selected or a coating is applied too thickly, heat rate penalties will likely be incurred.



10-24

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 isto mechanically expand the tube again, using a specially designed mandrel driven by an electricmotor. These mandrels are provided with between three and five rollers. The thickness of thetube to be expanded determines which mandrel is selected. Care must be taken to ensure that theallowable wall reduction is not exceeded.

Re-expanding can solve the joint leak problem, however, if the leak was caused by galvaniccorrosion between the tube and tubesheet, the problem might return. This is because of thecontinuing degradation of the tubesheet from galvanic action. Also the re-expanding of tubesmight place stresses on adjacent tubes and result in their experiencing tube-to-tubesheet jointleaks. Further, when re-expanding tubes into the tubesheet that is made from a copper-bearingalloy, such as Muntz metal, naval brass, silicon bronze, etc., great care should be taken to avoiddamaging 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 coatingsstarted 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 thetubesheet is required and the tubes must be protected from the blast by the insertion of blastplugs. Similarly, when subsequently applying the coating to tubesheets, plugs need to be insertedinto the tubes to protect them. Otherwise, NDE procedures and tube cleaning can be hamperedby material mistakenly left in the tubes.

Tubesheet cladding projects have been completed with the unit on-line. Waterbox isolationis required for this to occur. It is highly recommended that throughout the cladding process, allenvironmental control equipment, such as dehumidification and dust collection systems, beplaced in full operation. A picture of a tubesheet with an epoxy cladding is shown inFigure 10-13.



10-25

Figure 10-13Epoxy Tubesheet Cladding (courtesy of Plastocor)

Key Technical Point

Manufacturers recommend that epoxy coatings not be subjected to hightemperatures (> 170°F (76.6°C)) or allowed to freeze. If tubes, mounted intubesheets that have had the cladding applied subsequently, leak, theyshould not be plugged with tapered brass or fiber plugs. Expandable plugsare preferred because they do not put pressure on the coating. Plugs shouldnever 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 than3,000 psi (20.7 megapascals) should never be used. Also high-pressure water should not be usedto clean tubes that have been coated internally. Finally, tube-cleaning nozzles should never bemade from brass or other metals. The nozzles should be made from a soft plastic material toprevent 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 theinsertion of a rod between the tube rows locking the tubes in place. The rod prevents tubeoscillation and subsequent mechanical damage. The condenser tube stakes are generallyfabricated from stainless steel (Figure 10-14). Micarta, which is a much lighter material thatcannot be bent, is also used. A gap of 3/4 inch (19 mm) between tube rows is needed for theinsertion of a micarta stake (Figure 10-15).



10-26

Figure 10-14U Stainless Steel Tube Stake [33]

Figure 10-15Micarta Condenser Tube Stake [33]

Another type of tube stake is the Cradle-Lock® shown in Figure 10-16. The stake is stampedfrom stainless steel and is in a V shape with indentions at the tube locations. When installed, thespring 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 stakescan do.



10-27

Figure 10-16Cradle-Lock® Tube Stake (courtesy of the Atlantic Group)

A non-metallic, polymer stake known as a Lath® has been used in condensers where the steamtemperature does not exceed 300ºF (149ºC). The stake is an extruded polymer tube that has theair evacuated, is flattened in ribbon form, and sealed at the end. It is installed by threading theLath into the tube bundle and the end is cut to allow the air to re-enter. The polymer tube tries toretake its tubular form, thus cradling the condenser tubes.

The pattern of staking will vary with the condenser manufacturer’s tube bundle design. Thestaking pattern for a typical design is shown in Figure 10-17.



10-28

Figure 10-17Typical Condenser Tube Staking Pattern [33]

Staking should be provided all the way around the top of the tube bundle and approximately 80percent of the way down the side of the tube bundle. These areas see the impingement of wetsteam causing destructive tube vibration. Additional staking might be required at high-energydumps below these levels. If this involves staking the bottom and lower 20 percent of thebundles, specially designed clamping devices might be required. Staking is generally the least



10-29

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 issmaller than the original material tubes. This can create vibration problems when using the sametubesheet support spacing. The addition of tube stakes is needed to prevent any damage fromvibration.

10.10 Waterbox Repairs [12]

Waterbox restoration can include coating the entire waterbox, the most corroded section of thewaterbox, or patch repair of through-wall penetrations.

Key Technical Point

The material selection for coating waterboxes depends on whether thewaterboxes are new or have been in-service, coated in a manufacturer’sshop, or coated inside the plant. When coating new waterboxes, epoxies,rubber lining, or solvent-filled epoxies (coal tars) are used. Waterboxescoated inside the plant use epoxy coatings for performance, longevity, andpersonnel safety considerations.

Waterbox coatings are often used with cathodic protection systems. A coating greatly reduces theanodic area to be protected by the cathodic protection system. Generally, the most affected areain 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 erosionmechanisms. They act as a barrier between the corrodable metals and the circulating water andrehabilitate degraded metal surfaces by filling pits and depressions. This results in the restorationof a corroded surface to a smooth surface and helps to control biofouling.

Leak repairs require some waterbox drying and localized sandblasting or chiseling. Carbon steelpatchplates sized to cover through-wall holes are then used with elastomeric coating materialssuitable for circulating water exposure. The patchplates in the elastomer coating promote leaktightness 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 thewaterbox and the cost to perform repairs. While cast-iron was used as a waterbox material in thepast, the newer waterbox materials include carbon steel, carbon steel clad with 316 or 317stainless steel, 316 or 317 stainless steel, aluminum bronze, and titanium.

The tasks associated with the waterbox repair and replacement options are summarized inTable 10-2.



10-30

Table 10-2Waterbox Tasks for Repair and Replacement [12]

Task WaterboxPatch

WaterboxCoating

WaterboxReplacement

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

InterferenceReinstallation

NO NO YES

Cathodic ProtectionSystem

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 thewaterbox includes several techniques for a successful application:

x Surface Preparation and Lining - Heavy deposits of sludge or grease should be removedby scraping or dry wiping before general solvent cleaning and abrasive blasting. Solventwiping such deposits first has proven unacceptable because this process tends to smear thecontamination.

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 notmore than a trace contaminant of iron. Do not use steel shot or black beauty. These tend tobecome embedded in the surface and can produce film flaws.

Before coating, damage to the internal surfaces should be repaired and all residue of blastabrasive removed from the surface to be coated. The final step of the cleaning operationshould be vacuum cleaning. Blowing down with air is not an acceptable method of removingdust.

x Coating Material - Coating material should arrive in the original, unbroken containers. Thecontainer labels should be clear and intact. The date of manufacture or the expiration dateshould be marked on the label. Coating materials should be less than 6 months old whenapplied. 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 wouldaffect the solids content, the material should not be used. Mixed materials should be strainedbefore use.



10-31

x Coating Application - The coatings should be applied in accordance with industry standardsand the applicable instructions of the coating manufacturer. The following considerationsshould be detailed in the coating procedures:

– Material storage

– Surface preparation (finishing details, degreasing methods, type of blastingequipment, 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 withrequired limits during application)

– Force curing (available system capacity, heating cycle)

– Film repairs (means of restoring lining at areas outside thickness limits, holidays anddamaged spots, differentiate between nominal and major repairs)

Runs and sags should either be brushed out while the material remains wet or removed bysanding and touched up.

Adequate traps and separators should be provided to remove oil and condensate from thecompressed air supply. Solvent left in spray equipment to prevent overnight hardening or forcleaning 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 ofthe first coat. The coating should be worked vigorously into crevices; the material should bethinned as required to facilitate brushing.

The environment in the coating area should be controlled to ensure that the minimumtemperature is not less than 60qF (15.5qC) and that the surface to be lined is at least 5 degreeswarmer than the dew point.

The lining material manufacturer’s recommendations should be observed with regard tominimum and maximum drying times between coats. The ambient temperature in the coatingarea will be a function of the drying time.

Ample ventilation air should be provided to permit total removal of solvents and to maintain anatmosphere well below the explosive limit.

The coating should be free of visible fish-eyes, craters, and bubbles as well as overspraylamination to the extent that no visible imperfections remain.



10-32

A forced cure and a high-voltage, high-frequency film continuity test are the final steps incompleting a coating system. To improve the probability of a successful final test, it is suggestedthat a low-voltage (wet sponge type) holiday detector test be performed and imperfectionsrepaired prior to the forced cure. It should be noted that high-voltage spark testing cannot beperformed 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 thefinal 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 eliminatecorrosion beneath the tubesheet-to-waterbox gasket surface. This can result in condenser waterand/or air in-leakage along the corrosion path and through the bolt holes. The sealing of thisinterface has been performed successfully over the years by coating the interior surface of thetubesheet and waterbox flange joint. The coating materials developed for this purpose have beendesigned to withstand the potential for differential movement between the tubesheet andwaterbox. As with all applications of epoxy material, proper surface preparation and the use ofenvironmental 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 problemswith the tubesheet. If the tubesheet face is deteriorated and the thickness has been reduced, then acoating repair will not restore the structural integrity of the tubesheet. If the tubesheet has erosionof the tubehole surfaces with excessive leakage of cooling water to the condensate then coatingsmight be a viable option. The decision to coat tubesheets must include an assessment of tubeconditions. When replacing the tubesheet, the tubes must be cut inside the tubesheet face forremoval. This necessitates that new tubes be installed.

It is possible to coat the existing tubesheets using the existing tubes if the tubes are in goodcondition. Other considerations associated with tubesheet repairs are surface preparation andwaterbox coating. Prior to the coating application, the existing tubesheet surfaces must berefinished 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 materialbecoming sacrificial to the tube material. The coating of the waterbox surfaces might be requiredif the tubesheets are coated.



10-33

Table 10-3 shows the tasks associated with tubesheet repairs and replacement.

Table 10-3Tubesheet Tasks for Repair and Replacement [12]

Tasks TubesheetRepairs

TubesheetReplacement

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 fordestructive metallurgical analysis. After the unit is shut down, the condenser has cooled and thewaterbox doors are opened, the process of removing a tube can begin. If a tube plug or tubeinsert is present, these must be removed first. The tube can then be cut free from the tubesheet onthe end opposite the removal direction with an internal tube cutter. The tube should be cut aminimum 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 isoperated by inserting the head into the tube and actuating it. This causes the draw bar to exert aradial force and engage the teeth with the tube. As the device retracts, it pulls the tube outapproximately 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 plugboth ends of the tubesheet. Plugging the tubesheet end of the pulled tube hole is an importantoperation. If a plug from the tubesheet becomes dislodged, the consequences of such a large leakcan cause a forced outage. Use of a tube plug and tube plugging method with a high degree ofseal integrity is recommended.

10.13 Miscellaneous Repairs [3]

Experience has shown that water in-leakage can be caused by leaking piping that runs throughthe condenser and/or waterbox. One example is drain piping from a low-pressure turbine bearingthat runs vertically below the bearing through the waterbox. Leaks from such sources are hard tolocate because they are hidden from view and the leak rates are very small. It is important toreview plant drawings to identify all sources of potential leaks.


11-1

11 REMAINING LIFE, MATERIALS, ANDCONSTRUCTABILITY [3,12]

Condenser tube leaks are the major source of water in-leakage and a cause for reduced unitgenerating capability. The Operating Plant Experience Code data (Section 8.1.5) from April1998 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 thepercentage of tubes plugged has significantly impaired heat transfer capacity. Condenser designis such that there is typically excess surface area available in the form of extra tubes to allow asmany as 10% of the tubes to be plugged without reducing the effective heat transfer capacity ofthe 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 andthe capability of the unit for full power production. Utilities typically then consider retubing thecondenser to restore performance and extend the operating life expectancy of the unit.

Experience with new materials, new tools, and new techniques has significantly reduced waterin-leakage problems due to tube leaks and has improved condenser reliability. This has allowedstate 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 bundlereplacements have been very successful using shop-fabricated modules. Consequently, unitsconsidering condenser retubing are not faced with only one option, that is, to replace the existingtubes with new tubes of the same material and construction. In most cases, condensers operatingwith the original materials have experienced performance problems. The majority of problemsinclude water chemistry (both cooling water and condensate), tube fouling, and tube wallthinning issues. The design of the tube bundle replacements should take this experience intoaccount. Because condenser retubing represents a major capital investment, economic factorsweigh heavily in the decision-making.

Key Technical Point

The current industry experience has been to replace copper-bearing alloyswith high alloy, pit-resistant steels and titanium. These materials aresignificantly lighter in weight and higher in yield strength, but they havelower thermal conductivities than the copper-bearing alloys.

Use of these newer materials can significantly affect the performance characteristics of thecondenser. Typically, thinner-walled tubes of the same outside diameter are selected from thesealloys in order to reduce the tube wall thermal resistance and compensate for the loss in thermalconductivity. This tradeoff results in a larger tube side flow area but lower flow velocity. Thelower flow velocity increases the fouling potential for the condenser tubes and might require the


Remaining Life, Materials, and Constructability [3,12]

11-2

addition of an on-line tube cleaning system. The lighter weights of the tube bundles also result ina change in the condenser support loads and might increase the condenser hold-downrequirements.

Key Technical Point

Another consequence of retubing with one of the newer materials is thelikely need for additional tube support plates or tube staking to reduce thetendency of the tubes to vibrate.

More information on tube staking can be found in Section 10.9. There is the potential for brittlefracture of these high strength materials. The high yield strength of these materials makes it moredifficult to seal the tube-to-tubesheet joints if the original copper-bearing alloy tubesheets areused. The galvanic compatibility of the new tubes with the tubesheet has to be considered. Thismight 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 comprehensiveengineering and economic evaluation should be performed to arrive at the best retubing optionfor a given unit and site location. Most of the concerns that should be considered in acomprehensive 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



11-3

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 maintenancerecords reveal present and past problems within the condenser. This includes the rate atwhich the conditions might be changing. In addition to providing location and date ofplugging, possible reasons for failure should be recorded.

x Historical Data – Industry data defining expected component life could provide a basis formore extensive condition analysis.

x Non-Destructive Examination (NDE) – The use of NDE testing can provide valuableinformation on the remaining life of condenser components. Testing techniques include:Visual Inspection (VI), Dye Penetrant Testing (PT), Magnetic Particle Testing (MT), EddyCurrent Testing (ET), and Ultrasonic Testing (UT). Additional information on NDE testingcan 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 bymetallography, micrometer measurements, etc. should be performed to verify NDE resultsand to confirm specific failure mechanisms. It is very difficult to predict remaining lifewithout 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 remaininglife. 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 probablecause of failure. Tube failures primarily occurring in the periphery suggest outsidediameter impingement or water level problems. Problems with brass tubes in and



11-4

around the air-removal zone suggest condensate grooving. High failure rates in lowportions of the bundle suggest siltation problems.

– Substantial differences in the amount of corrosion occurring between the upperand 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 inspectionindicates cracks.

x Magnetic particle testing is used to detect cracks in spargers, and penetration and bafflewelds.

x Eddy current testing is used to examine the condition of the installed tubes. An internalprobe 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 thetube. Wall thinning, cracks, pits, and other defects interrupt this field causing a measurableimpedance change in the coil. Indication of condenser tube defects are shown on a visualscreen and recorded. The nature and magnitude of all defects are determined by comparisonof 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 materialand the reflections of the sound waves caused by defects in the material are measuredelectronically. The sound is generated by a probe containing a piezoelectric disc that convertselectrical current into mechanical vibrations. The results are recorded and compared tocalibration 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 extratubes to allow as many as 10% of the tubes to be plugged without reducing the effective heattransfer capacity of the unit. [12]



11-5

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 tubesindicates that the tubes are free from corrosion or cooling water erosion related failures overthe range of condenser applications. The material is rated as superior in fresh, salt, andbrackish water applications. Also, the experience with welded tube-to-tubesheet joints withtitanium or titanium-clad tubesheets has been good. Titanium has a relatively low elasticmodulus (15 E+6 psi) (103 E+6 kilopascal). Flow-induced vibration considerations require acloser tube support spacing for titanium tubes compared to tubes of other commonly usedmaterials.

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 relativelyhigh (29-30 E+6 psi) (200-207 E+6 kilopascal) elastic modulus of this stainless steel alloyallows the tubes to be utilized in retubing applications without changing the tube supportspacing. Welded tube-to-tubesheet joints have not been used with modified stainless steeltubes.

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 withrecirculating and once-through cooling water. Experience indicates that corrosion failures oftypes 304 and 316 stainless steel condenser tubes are not common in recirculating watersystems with cooling towers, freshwater makeup, and chloride levels below 300 ppm. Thisservice 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 limitthe use of type 304 and 316 stainless steel tubes to freshwater and freshwater makeup coolingtower applications. Welded tube-to-tubesheet joints have not been used for type 304 or 316stainless steel tubes. This could be due to concern over tube weld shrinkage stresses incontact with chloride-containing cooling waters.

x Copper-Alloy Tubes: A large number of condensers have used copper-alloy tubes withAdmiralty brass tubes in freshwater service and aluminum bronze, aluminum brass, andcopper-nickel tubes in saltwater, brackish water, and freshwater service. Corrosionperformance has varied with these materials being sensitive to polluted applications. Theability of copper oxides to perform as an oxidizing species in steam generators has led to thereplacement 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 toavoid corrosion from ammonia and carbon dioxide attack.



11-6

11.2.1 Titanium

The specification requirements are:

x Tubes shall be made from a commercially pure titanium alloy in accordance with ASTM B338 Grade 1 with a maximum oxygen concentration of 0.14%. The major differencesbetween 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 providesadditional ductility for expanding the tubes into the tubesheets.

x Seamless or welded tubes should be specified. If welded tubes are specified, the strip shouldbe required to be in accordance with ASTM B265 Grade 1. Supplementary Requirement S-1of ASTM B265 (Surface Requirement Bend Tests) should also be invoked.

x The tube wall thickness must be specified. Presently used thicknesses for U.S. applicationsvary from 0.020 to 0.035 in. (635 to 889 Pm). Retubed units are sometimes limited to a wallthickness 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 of0.020 in. (635 Pm). This is in addition to new condenser units using titanium tubes with awall thickness of 0.020 in. (635 Pm).

The non-destructive eddy current or ultrasonic tests of each tube should be in accordancewith ASTM E213 for ultrasonic testing or with ASTM E243 for eddy current testing, exceptthat 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 steelindustry led to the development of a family of extremely chloride-resistant materials known asthe high performance stainless steels. These grades were designed to use a combination of highchromium and molybdenum to provide economy and the ability to withstand severe corrosiveservice. One of the target applications was steam condenser tubing for power plants usingseawater or brackish water for cooling. For this application, a group of alloy types emerged andis shown in Table 11-1.



11-7

Table 11-1High Performance Stainless Steel Tube Material [36]

CommonName

UniformNumberingSystem No.

Type Co. Trade-Marks

Chromium(%)

Nickel(%)

Molybdenum(%)

Nitrogen(%)

Other(%)

AL-6X N08366 Austenitic AlleghenyLudlum

20 24.5 6.2 0.02

AL-6XN N08367 Austenitic AlleghenyLudlum

20 24.5 6.2 0.20

254 SMO S31254 Austenitic Avesta AB 20 18 6.2 0.20 0.8 Cu

654 SMO S32654 Austenitic Avesta AB 25 22 7.5 0.50

AL 29-4C S44735 Ferritic AlleghenyLudlum

29 - 4.1 0.01 0.4 Ti

SEA-CURE

S44660 Ferritic CrucibleMaterials

27 2.2 3.7 0.01 0.4 Ti

290 Mo S44375 Ferritic Vallourec 29 - 4 - 0.4 Ti

29Cr-3Mo

None

Ferritic Vallourec 29 - 3 0.4 Ti

NuMonit S44635 Ferritic Avesta AB 25 4 4 0.4 Ti

FS10 S44800 Ferritic SumitomoMetal 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 certainproperties important to condenser tube service. The newest of these grades, S32654, is distinctlydifferent from the others. It has significantly higher corrosion resistance because of its highnitrogen content. All the other grades can be considered technically equivalent in terms oflocalized 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 minimumannealing temperature of 2100 qF (1149qC), followed by a water quench should be specifiedto prevent a sigma phase rich in molybdenum from forming. Tensile and elongation tests inaccordance with ASTM E 8 should be required for the strip used in manufacturing of thewelded tubes. Either UT or ET should be specified. UT examination for both seamless andwelded tubes should be in accordance with ASTM E 213, supplemented by ASTM E 273 forwelded tubes.

x Eddy current examination should be required to comply with ASTM E 426 or E 571.



11-8

x SEA-CURE, NuMonit or AL 29-4 tubes shall be in accordance with ASTM A 268 andASTM 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 requirean air leak test for each tube. Either UT or ET should also be specified. UT examination forboth seamless and welded tubes should be in accordance with ASTM E 213 supplemented byASTM E 273 for welded tubes. Eddy current examination for the ferritic material will requiremagnetic 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 atthe United Illuminating Bridgeport Harbor Station. The grade used was the original, low-nitrogen version of the modern 0.20% nitrogen austenitic stainless steel, AL-6XN (NUSN08367). The plant is located on Long Island Sound and the cooling water is essentiallyseawater. After an initial period of evaluation extending to about 1977, other installations beganwith rapid escalation after 1980. Figure 11-1 shows the number of installations per year. Over200 installations have been made through 1998. This represents nearly one hundred million feetof installed tubing. These installations include all of the stainless steels described in Table 11-1and a variety of cooling waters ranging from heavily polluted seawater to clean freshwater.

Figure 11-1High Performance Stainless Steel Installations [36]



11-9

11.2.2.2 Water Type Significance

Seawater and brackish water-cooled condensers were originally thought to be the prime areas ofapplication for the high performance stainless steel tube materials. This was based on the goodchloride resistance of these materials and the fact that materials such as Admiralty brass and type304 stainless steel are generally considered suitable for handling fresh cooling waters. Technicalreasons cited for Admiralty brass failures at freshwater sites include suspected sulfide pittingand, with type 304 stainless steel, under-deposit manganese pitting or microbiologicallyinfluenced corrosion. Type 304 can replace Admiralty Brass that is suffering sulfide pitting at asubstantial cost saving compared to the high performance stainless steels. The reasons for usinghigh 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 11-2High 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 tubesheetcrevice corrosion, pitting corrosion, tubesheet galvanic corrosion, hydrogen cracking, andvibration fatigue. These failure mechanisms are discussed in Section 8.2 of this report. The datais shown in Figure 11-3.



11-10

Figure 11-3High Performance Stainless Steels Problem Incidents [36]

Specific Cases of Tubesheet Crevice Corrosion:

The high incidence of tubesheet crevice corrosion with an austenitic alloy involves fivecondensers 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 ofjoint had been successful at the utility with the previous type 316 stainless steel tubes thateventually failed by pitting. However, with the installation of the new, austenitic N08367 highperformance stainless steel tubes, crevice corrosion of the tubesheet bore was noticed afterperiods of four to eight years in units at one plant site and after just a few months at another plantsite. The corrosion was severe enough to require correction action. A tubesheet coating wasapplied at the less aggressive site and a combination of coating and cathodic protection wasapplied at the more aggressive site.

Based on this experience, and the fact that gaskets are known to be initiators of crevice corrosioneven 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 stainlesssteel tubesheet is considered for use with the high performance stainless steel grades, thetubesheet should have corrosion resistance at least equal to that of the tube material.



11-11

Specific Cases of Tube Pitting Corrosion:

Tube pitting corrosion has been reported at seven installations. All of these cases involvecondensers where high-chloride brackish or seawater is used for cooling. In contrast, there havebeen no reports of pitting or any other form of corrosion at the freshwater sites. In all four casesinvolving 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 moderncounterpart, 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 withAL29-4C. The applications of SEA-CURE were in 1981 at Port Everglades #2 and in 1982 atIndian River #2. Based on the experience at Port Everglades, the original chemical compositionwas determined to be too lean and was subsequently enhanced with increased molybdenum andchromium. In addition, the possibility of a high tube wall temperature near a steam dump mightalso have contributed to the pitting at Port Everglades. The Indian River #2 site is unusual in thatthe cooling water chemistry produces severe inorganic fouling deposits. Pitting was not noticeduntil much later. The benefit of frequent cleaning in controlling pitting suggests that under-deposit 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 occurredat the Northside #3 station with alloy AL 29-4C. Full penetration pits developed in three tubeswith other pits present one year after startup in 1990. Suspected causes were excessive targetedchlorination, manufacturing oxide and defects, sulfate reducing bacteria and an extended downperiod without draining or flushing shortly after retubing. In the last few years the frequency ofpitting has declined.

A summary of each of these cases is provided in Table 11-2.

EP

RI

Lic

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d M

ater

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Rem

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11-1

2Tab

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[36]

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11-14

11.2.3 Austenitic Stainless Steel [35]


x Type 304 stainless steel tubes shall be in accordance with ASTM A 249 for welded tubes andA 213 for seamless tubes (UNS-30400) and ASTM A 450. A minimum annealingtemperature of 1900qF, followed by a water quench or by cooling by alternate means to800qF in less than one minute, should be specified. Supplemental Requirement S-3 of ASTMA 249 should be invoked to require an air leak test for each welded tube. Either UT or ETshould also be specified. UT examination for both seamless and welded tubes should be inaccordance with ASTM E 213, supplemented by ASTM E 273 for welded tubes. ET shouldbe in accordance with ASTM E 426.

x Type 316 stainless steel tubes shall be in accordance with ASTM A 249 for welded tubes andA 213 for seamless tubes (UNS-31600) and ASTM A 450. Other requirements should beidentical to those discussed above for Type 304 tubes.

11.2.4 Copper Alloys [35]


x 70-30 Cu Ni tubes shall be in accordance with ASTM B 111 or B 543. The tubes should bespecified to be in the annealed condition. Tensile tests and mill test reports should berequired. 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 bespecified to be in the light drawn temper condition. Tensile tests and mill test reports shouldbe 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 andmill 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 andmill 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 C44500). Tensile tests and mill test reports should be required. ET in accordance with E 243should be specified.



11-15

11.2.5 Summary of Material Specification [35]

See Table 11-3 for a summary of condenser tube material specifications.

Table 11-3Condenser Tube Material and Testing Specifications [35]

Tube Material Material Specification Testing Specification

Titanium ASTM B338 Grade 1, 2 seamless

ASTM B 265 Grade 1 welded strip

ASTM E 213 UT

ASTM E243 ET

AL6X ASTM B 676 Class 2, UNS-N08366

ASTM E-8 welded strip

ASTM E 213 UT

ASTM E 426 or

ASTM E 571 ET

SEA-CURE

NuMonit

Al 29-4C

439 Stainless Steel

ASTM A 268, UNS S44660

UNS S44635

ASTM A 268, UNS S44375

ASTM A 268, UNS 43035

ASTM E 213 UT,

ASTM E-273 weld

ASTM E 309 ET

304 Stainless Steel ASTM A 249 welded, UNS S30400

ASTM A 213 seamless

ASTM A 269

ASTM E 213 UT,

ASTM E-273 weld

ASTM E 426 ET

316 Stainless Steel ASTM A 249 welded, UNS S31600

ASTM A 213

ASTM A 269

ASTM E 213 UT,

ASTM E-273 weld

ASTM E 426 ET

70-30 Cu Ni ASTM B 111 seamless

ASTM B 543 (C 71500) welded

ASTM E 243 ET

90-10 Cu Ni ASTM B 111 seamless

ASTM B 543 (C 70600) welded

ASTM E 243 ET

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



11-16

11.2.6 Material Comparison [35]

See Table 11-4 for a comparison of condenser tube materials.

Table 11-4Condenser Tube Material Comparison [35]

Material Advantages Disadvantages

Superior corrosion resistance High costTitanium

Weldable tube-to-tubesheetjoints for leak-tight integrity

Subject to hydriding if cathodicprotection is not operatingproperly

AL-6X, AL-6XN Excellent corrosion resistance High cost

300 Series Stainless Steel Very good corrosionresistance in low-chloridefreshwater

Subject to various forms ofunder deposit corrosion andcrevice corrosion

Very good corrosionresistance in low-chloridefreshwater

400 Series Stainless Steel

Better heat transfer coefficientthan 300 series stainless steel

Subject to severe corrosion insulfide bearing water

Cu Ni Alloys Very good corrosionresistance in unpolluted water

Subject to inlet end andblockage erosion

Good corrosion resistance inunpolluted brackish orsaltwater

Subject to inlet end andblockage erosion

Aluminum Brass

Excellent heat transfercoefficient

Subject to condensategrooving

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.



11-17

Figure 11-4Typical 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 isdeformed, 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 thetubesheet to the hole.

Most operating condensers use expanded tube-to-tubesheet joints. Advantages of the expandedjoint in comparison to a welded joint are that it is easy to form at original construction and allowscondenser retubing with minimal effort. Depending on tightness requirements and materialcombinations, an expanded joint can also be re-expanded. This, however, might be difficult withtitanium tubes.

Disadvantages of the expanded joint are that it has less axial load carrying capability than anexpanded and welded joint for currently used tubesheet thicknesses. It does not provide aspositive a seal between condensate and cooling water as a welded joint. The expanded joint isalso less tolerant to tubesheet hole out-of-roundness. Use of an expanded joint only with a carbonsteel tubesheet clad with titanium can have a potential leak path between the circulating water



11-18

and carbon steel base material. This is dependent upon the thickness of the titanium claddingmaterial.

Over-expanding can result in tubesheet damage, excessive thinning of the tube wall, and workhardening 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 tubepullout appear to be inadequate analysis of the tubesheet/flange, lack of acceptance criteria forjoint loads, poor quality control of the expansion process, lack of proper cleanliness, and poorquality control of the tubesheet hole geometry.

The expanded joint is usually formed by mechanical expansion. In mechanical expansion, aroller expander has roller bearings mounted in a cage that rotates at speeds of 400 to 1,000 rpmaround a tapered mandrel. The mandrel is forced into the bearing cage, which causes each rollerto move radially outward and expand the tube.

Most roller expanders have three roller bearings, however, for stainless steel and titanium fiveroller cages are commonly used. Other techniques that might be used are hydraulic and explosiveexpansion. Hydraulic expansion is accomplished with a pressurized liquid, which expands thetube into the tubesheet. The length of tube expanded is determined by o-ring seals on theexpansion probe. Explosive expansion is accomplished with an explosive charge that is placed inthe tube and then remotely detonated. The force of the explosion expands the tube into thetubesheet 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 anexpanded joint. With a single groove the allowable load can be increased up to 30% dependingon the materials used. Two grooves might increase the smooth hole allowable by 40% for certainmaterial combinations. A typical groove depth is 1/64 inch (3.8 mm). The mechanical pulloutstrength developed by a particular rolled joint does not necessarily reflect the capability of thejoint to provide a seal between the condensate and the cooling water. Smooth pre-rolled tubeholes have been found to be the best for high-pressure leak tightness and groove holes appear todevelop 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 andtubesheet.

11.3.4 Expanded and Welded Joint

Most experience with welded tube-to-tubesheet joints involves fusion welding. The fusion-welded joint can be a strength weld that carries the entire joint load and performs the sealingfunction. Alternatively, the joint can be a seal weld that augments an expanded joint by



11-19

providing greater leak integrity but is not considered a load-carrying member. Tube andtubesheet materials preferable for welded joints are stainless steel and titanium. If titanium isused 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 canprovide greater axial strength and better leak integrity than an expandedjoint for titanium and stainless steel tubes with tubesheets of weldcompatible 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 environmentallycontrolled conditions as the original weld.

Roller expansion in conjunction with welding should be done without lubricating oil. Thelubricating oil gets into the space between the tube and the tubesheet where it cannot beremoved. The presence of lubricating oil could result in weld porosity.

Welded joints will complicate retubing because of the difficulties of grinding or machining outthe tube to tubesheet welds. For this reason, welded tubesheet joints are recommended only fortube 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 tosupplement expansion, it can increase the pullout strength. Anaerobic adhesives, such asLoctite®, will cure when oxygen is excluded. Surfaces to be bonded must be clean and free ofoil 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 yieldstrength of the tube material to facilitate satisfactory expansion of the tubes into thetubesheet.



11-20

x Electrochemical Potential: The tubesheet material should be relatively noble to minimizethe requirement for cathodic protection.

x Weldability: Where the tube-to-tubesheet joint includes a seal weld between tube andtubesheet, the tubesheet material must be weld-compatible with the tube material.

x Machineability: The tubesheet material should be readily machinable to facilitate thedrilling of the tube holes in the tubesheet. It is particularly important that the surface of theas-drilled holes be smooth and free of tool chatter.

x Flatness: Tighter flatness tolerances are required with higher strength tubesheet materialsfor an acceptable tubesheet to waterbox flange joint. Weaker tubesheet materials such asMuntz metal, will readily conform to the waterbox flange. Flatness tolerances for materialssuch as stainless steel or titanium should be reduced to half of that previously specified forweaker materials.

A summary of the tubesheet material recommendations is shown in Table 11-5.



11-21

Table 11-5Tubesheet Material Recommendations [35]

Tube Material Tubesheet Joint Type Tubesheet Material ASTM Specification

Welded Titanium B 265 Grade 1, 2, 3Titanium

Expanded but notwelded

Carbon Steel cladwith Titanium

A 285, A 515 or A 516clad with B 265 grade1, 2 or 3

Stainless Steel A 240 TP 409, 410 or316

Aluminum Bronze B 171

AL-6X Expanded

Carbon Steel cladwith Stainless

A 515 or A 516

Sea-Cure

AL 29-4C

NuMonit

Expanded Stainless Steel

Carbon Steel cladwith Stainless Steel

A 240 TP 409, 410,316

A 515 or A 516

Welded Stainless Steel A 240

Stainless Steel A 240


Type 304 StainlessSteel Expanded


A 515 or A 516

Welded Stainless Steel A 240

Stainless Steel A 240


Type 316 StainlessSteel Expanded


A 515 or A 516

70-30 Cu Ni B 17170-30 Cu Ni Expanded


90-10 Cu Ni B 171

70-30 Cu Ni B 171


90-10 Cu Ni Expanded

Muntz Metal B 171

90-10 Cu Ni B 171

70-30 Cu Ni B171


Aluminum Bronze Expanded

Muntz Metal B 171

90-10 Cu Ni B 171

70-30 Cu Ni B 171


Admiralty Metal Expanded

Muntz Metal B 171



11-22

11.4 Waterbox and Shell Materials [35]

Improper selection of waterbox and shell material could greatly accelerate galvanic corrosionand shorten condenser life. In many condenser applications, the waterbox is anodic relative to thetubes and tubesheet and provides some degree of cathodic protection to the tubes and/ortubesheet. For example, cast-iron waterboxes provide some degree of protection to copper-alloytubes and tubesheet. This degree of protection will be reduced in-service as the cast-irongraphitizes 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 toreduce the rate of biological fouling of the waterbox. Other waterbox linings include rubber, coaltar, and epoxy coatings. Typical materials for shell and waterboxes are shown in Table 11-6.

Table 11-6Condenser 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 andsupports. Major material requirements include the tubes and anti-vibration tube stakes. Itmight be necessary to replace the tubesheet.

x A rebundling approach - Existing tube bundles and possibly sidewalls are replaced withshop-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 andsupport 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 notto damage the tubesheets. The installation of new tubes with staking and wedging to correctlyposition the tubes is time consuming. The attachment of the tubes to the tubesheet is a criticalprocess for leak-free joints.



11-23

For a retubing effort, procedures should be developed for the following tasks. The proceduresshould be approved by all parties involved, that is, the contractor, consultants, and theowner/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 forremoval of waterboxes. If this is not the case, lift points must be selected at various steelmembers within the building. The structure should be reviewed to ensure its ability to take theloads.

The lifting procedure should identify any beams that provide even load distribution duringwaterbox 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 thisequipment should be included in the procedure. Temporary structures and rigged equipmentshould 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 cathodicprotection system anodes should be removed. Circulating water pipe expansion joints should beremoved prior to waterbox removal. Butterfly valves interconnecting waterboxes should beremoved next. Miscellaneous connections can be removed simultaneously along with thepreviously discussed connections. The final connection to be broken should be the waterbox totubesheet joint.

Removal of old waterbox bolts is generally accomplished with an impact gun. Bolts that cannotbe removed with an impact gun can either be burned off or removed with a hydraulic device. Agood 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. Anumber of wooden wedges should be driven into the joint with sledgehammers until thewaterbox is broken loose.



11-24

Waterbox flange gasket surfaces should be inspected for defects and repaired beforereinstallation. Replacement rubber gaskets should be installed along with an appropriate caulkingmaterial 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 aresent in to each waterbox to start removal of any tube plugs and tube inserts. The old tubes are cutfree 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 shouldincorporate a pneumatic drive and manual control of the blade feed. The cutter head is designedto have a front-end sized to fit into the inside diameter of the tube and a cutting blade ofsufficient length to cut through the full wall thickness of the tube. During operation, the tool headrotates and the cutting blade is fed manually by either a lever arm or a steady pushing motionagainst the tubesheet to meet the inside diameter of the tube. A firm steady pushing force isapplied by hand until resistance to cutting disappears, indicating the cut is complete. The leverarm and/or tool are then retracted and the tube cutter moved to the next tube. Cutting edgesshould be kept sharp, because a dull tool might create a burr on the tube that could damage thetubesheet hole during the removal process. When cutting time increases significantly or the cutsstart to have rough edges, the cutting bits should be replaced.

The tube removal process starts with the tube joint being broken. Approximately every fourthjoint is broken and the associated tubes removed from the condenser. Tube stubs can be removedsimultaneously 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 andsupport plate hole reaming should begin. Damaged holes should be reworked in accordance withthe 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 accessand design.

Distortion of the tubesheet can occur as the tubes are cut free because the tubesheet isstructurally 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 theinside diameter and wall thickness of the specific tubes. The device is operated by inserting thehead into a tube and actuating it, causing the draw bar to exert a radial force and engage the teethwith the tube. As the device retracts, it pulls the tube out approximately 4 in (10 cm) from thetubesheet. This breaks the roll to the tubesheet. Releasing the trigger of the device frees the drawbar and the machine can then be moved to the next tube. Due to the size of the extraction tool,



11-25

approximately every fourth tube joint is broken and the tubes removed. The number ofsimultaneous 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 bymeans of a hydraulically driven extractor. The extractor functions by placing individual tubesprojecting approximately 4 in (10 cm) from the tubesheet into the extractor opening. An internalset of gears grabs the tube and pulls it through the extractor flattening the tube to a ribbon as it ispulled. The flattened tube can then be fed into a tube chopper where the ribbon is cut intoapproximately 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 oflubrication 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 tubebundles, individual tubes can be removed in the core of the bundles and perforated tubesinstalled in their place. Water supply hoses can then be connected to the tubes to insure completewetting of the bundle.


Recent improvements in technology have resulted in tooling that can pull anentire tube and chop the tube into pieces in a single operation at thetubesheet. This improvement is significant because it reduces both the laborand space required for tube removal.

The procedure of pulling tube stubs from the tubesheet is identical to that used for pulling tubeswith one exception. As the machine is removed from the tube hole, the stub left from the cuttingprocess 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. Shouldremoval space be a problem, the waterboxes opposite the tube removal direction need only to beremoved a sufficient distance to replace the tubesheet (this includes access and riggingclearances). Tube plugs and tube inserts should be removed as both ends of the tubes are cut freefrom the tubesheets using internal tube cutters. The tubesheets can then be removed from theshell expansion joint (if installed). The expansion joint (or diaphragm) should be held in positionprior to removal of the tubes and tubesheets by means of blocking and welding of the alignmentplates. As with the waterbox removal, wooden wedges might be required to pry the tubesheetloose.

Caulking and dovetailing are necessary for the new tubesheet-to-shell flange gasket. Beforetightening bolts, the new tubesheet should be checked for hole alignment. Prior to tightening thenew tubesheet bolts, a number of tubes should be inserted in all sections of the tubesheet toensure that the holes are in reasonable alignment with the support plate holes.



11-26

11.5.1.6 Support Plate Deburring

Support plate holes are designed to be larger than the nominal tube outside diameter. Duringoperation of the condenser, a considerable amount of corrosion product accumulates in thecrevice between the tube and support plate. The net effect is that the clearance is reduced tovirtually zero. Usually this corrosion product remains even after removal of the old tubes. Toretube 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 severalhundred thousand holes might have to be reamed. An early start can prevent the operation frombecoming critical path. The number of people employed in this operation is a function ofcondenser shell access and available tooling. Reaming should be performed using pneumaticallydriven, spherical carbide burrs. As the burrs will become smaller through use, the burr diametersshould be checked at least twice a shift to ensure that they have not become too small. The burrsneed only pass quickly in and out of each support plate hole. Additional working of holes is laborintensive 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 axialgouges or scratches in the tube holes. Because these gouges might be several thousandths of aninch (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 withdamage 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 shouldaddress 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 thetotal holes but the cause of holes in this range must be investigated and corrected before anyfurther drilling.

x Holes exceeding the number of size tolerances discussed above must be repaired or pluggedand not used in the absence of test data demonstrating the adequacy of expanded joints in theholes.

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.



11-27

Table 11-7Tubesheet Hole Size Limits [6]

Nominal Tube OutsideDiameter in Inches (mm)

Lower Limit inInches (mm)

Upper Limit inInches (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 steeltubes into tubesheets with material of lower yield points such as Muntz metal. If the existingtubesheet 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 benchmarkholes. 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 beutilized.

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 orpermanently distorted. It is recommended that manufacturer’s storage and handling requirementsbe reviewed thoroughly and specific recommendations be incorporated into the tube installationprocedure.

Prior to tube insertion, the tubesheet holes should be washed with water. Tubes should beremoved one at a time from the shipping box in the retubing area. A tube pilot or bullet is theninserted into each tube. Personnel inside the condenser should guide the first few rows of tubesbecause the tubes are very flexible and might not go directly through the correct support plateholes. It is always advisable to have personnel inside of the shell to help with tubes that hang-upin the support plates. It is critical that the tubes be inserted in line with the tube holes. Adequatescaffolding should be provided inside the condenser. The new tubes inserted into the condensershould never be used as a work platform or walked upon.



11-28


Sufficient labor should be planned for tube insertion. Good practice is toprovide 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 endand 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 goingto 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-to-tubesheet joint integrity. It is important that the locations of the various heat numbers in thecondenser be recorded. This is best accomplished on tubesheet maps located on the tube pushingplatforms.

11.5.1.9 Expanding Tubes

When all tubes have been inserted and both tubesheets are in place, the waterboxes should bebolted in place. Although the addition of the waterbox will make tube expansion more difficult incertain areas of the waterboxes, it is recommended before rolling the tubes to the tubesheet. Thisis to make the entire tubesheet stiffer and to reduce distortion of the tubesheet during the rollingprocess. Clusters of tubes at both ends, scattered over the entire cross-section, should beexpanded to support the tubesheets and minimize tubesheet bowing.

Each tube to be expanded should be lubricated with a suitable water-soluble lubricant. Expansionof the tubesheet can be accomplished in any desired sequence. Prior to expansion of the oppositetubesheet, the clusters previously described must first be expanded in order to minimizedistortion. Expansion can then be performed in any desired sequence. As the expansion processproceeds, 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 effectedby monitoring apparent wall reduction. Apparent wall reduction should be calculated afterexpanding a maximum of 100 tubes per operator.

Before starting the retubing, a pullout test should be performed in order to determine the range ofapparent wall reduction that will produce the required tube-to-tubesheet joint strength for thecombination of tube and tubesheet materials being utilized. The range of apparent wall reductionachieved during the retubing should fall within the range determined by pullout testing. Torquecontrol 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 verydifficult to control within a desirable apparent wall reduction range. When expanding such acombination of materials, torque control must be used as the primary control criteria, whileutilizing apparent wall reduction as a check to determine if the tube end expansion is trendingeither too high or low.



11-29

11.5.2 Rebundling

A rebundling design constraint is that the turbine and concrete foundations are fixed. Themodular replacement bundle should be optimized based on tube density and tube size. The tubesize selected is usually between 7/8 and 1 1/4 inch (2.2 and 3.2 cm). The optimum layout isdependent on specific design conditions and economic factors. The ratio of the total nominaltube cross-sectional area to the total shell cross-sectional areas between the top and bottom of thebundle should be no more than 0.30 and preferably 0.25 or less. The desired limiting ratios basedon the original and new condensers should be included in the replacement specification so thatan informed decision can be made if the ratio cannot be satisfied. Space limitations often make itimpossible 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 storagedeaeration space, spargers, and so on. In the hotwell, the bundle height can be increased bypermitting 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 increasein the number of tubes. This increase in tube side flow area generally resultsin reduced condenser circulating water pressure drop and an increase incirculating water discharge from the existing circulating water pumps. Theresulting 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 equipmentlife. The leak-tight condenser will improve equipment availability. A rebundling approach canoffer the following advantages compared to a re-tubing approach:

x Replacement of the tubesheets with a material compatible with the tube materials eliminatesthe 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 anopportunity to increase heat transfer area and improve turbine performance, with a possibleincrease 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 tubesheetmaterial, the tube joints can be rolled and seal welded.

x Placement of intermediate tube supports to eliminate the need for tube staking. This is oftenrequired with the thinner gauge tubes and materials with a lower modulus of elasticity.


12-1

12 REFERENCES

1. Thermal Performance Engineering Handbook,Volume II. EPRI, Palo Alto, CA: November1998. TR-107422-V2.

2. Thermal Performance Engineering Handbook, Volume I. EPRI, Palo Alto, CA: October1998. 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: July1998. 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–CondenserApplication,” 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 PerformanceMonitoring,” Joint ASME/ANS Conference in Portland, Oregon (July 1982).


References

12-2

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-101840-V4P5.

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 Improvementof Heat Removal Capacity, 1999.

19. G.E. Saxon, Jr. and R.E. Putman, “Improved Condenser Performance Can Recover Up to 25Mw Capacity in a Nuclear Plant,” EPRI Nuclear Plant Performance Conference (August1995).

20. G.E. Saxon, Jr., R.E. Putman, R. Schwarz, “Diagnostic Technique for the Assessment ofTube Fouling Characteristics and Innovation of Cleaning Technology,” EPRI CondenserTechnology Symposium (1996).

21. Infrared Thermography Developments for Boiler, Condenser and Steam Cycle. EPRI, PaloAlto, 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 CondenserTechnology Seminar, EPRI, Palo Alto, CA (September 1-3, 1999).

26. Condenser On-Line Leak-Detection System. EPRI, Palo Alto, CA: December 1995. AP-101840-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,” PowerMagazine. (July 1985).

29. Dickinson, Wayne H., Miller, Larry. Manganese-Dependent Corrosion in an Open ServiceWater System.


References

12-3

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 HeatExchanger 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 StainlessSteel Tubing in Power Plant Steam Condensers,” 1999 EPRI Condenser TechnologySeminar, EPRI, Palo Alto, CA: (September 1-3, 1999).


13-1

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


Acronyms

13-2

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


Acronyms

13-3

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


14-1

14 GLOSSARY

Air Binding – the displacement of steam in the condenser with excess air that hinders the heattransfer 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 impedeswater flow, reduces heat transfer, and aids in corrosion.

Brush and Cage System – an on-line tube cleaning system that shuttles a captive brush inside thetube by reversing the direction of cooling water through the condenser.

Cathodic Protection – a water side corrosion control method that uses sacrificial anodes attachedto the waterbox.

Condenser On-Line Leak Detection System – (COLDS) – the EPRI-patented system that usestargeted injection of sulfur hexafluoride to detect and locate condenser tube leaks while the unitis 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 beconnected 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 isone method used in detecting air in-leakage.

Liquid Ring Vacuum Pump (LRVP) – mechanical pump used in the air-removal system of thecondenser. The liquid ring vacuum pump is a rotary, positive displacement pump that uses aliquid 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.


Glossary

14-2

Microfouling – the accumulation of inorganic scales or organic growths that deposit on the insideof condenser tubes.

Multisensor Probe (MSP) – an instrument located in the exhauster vacuum line that measures theamount of air in-leakage.

Non-oxidizing Biocides – systemic poisons that kill microbiological organisms by interferingwith their metabolism.

Oxidizing Biocides – poisons that kill or deactivate microorganisms by oxidizing the organiccomponent of the microorganisms.

Sparging – introducing steam into the condensate just above the hotwell level by use of steamnozzles. The sparging system functions mostly during reduced power operation and startup toreheat the condensate.

Sponge Ball System – an off-line tube cleaning system that uses the cooling water flow to pushor force slightly over-sized sponge rubber balls through the condenser tubes. The wiping actionof 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 jetfor the ejection of air and other non-condensables from the condenser compartment. It isnecessary to use several ejectors to obtain a sufficient vacuum.

Subcooling – the cooling of the condensate below the saturation temperature corresponding tothe condenser pressure. Condensate subcooling is caused by flooding the lower levels ofcondenser tubes with condensate. Hotwell subcooling occurs when the cooling water temperatureis so low that it causes a moisture decrease at the turbine blade outlet.

Technical Advisory Group (TAG) - a group composed of utility contacts, vendor representativesand consultants that provide technical review and oversight for EPRI developed products.

Terminal Temperature Difference (TTD) – the difference between steam temperature and outletcooling water temperature.

Tracer Gas Testing – a leak detection method used on a sealed container that requires a pressuredifferential to exist between the interior and exterior of the component being tested. The tracergas is placed in the area of higher pressure and migrates through leakage paths to the lowerpressure area.

Travelling Water Screens – a moving screen located before the circulating water pumps thatprevents large organic and inorganic material from entering the intake.

Tubesheet – a non-rigid structural member that holds the condenser tubes. The tubesheet consistsof several plates with holes drilled for tube installation. The plates at the end of the tubes have ajoint sealing arrangement.


Glossary

14-3

Waterbox – a plenum for cooling water entering and exiting the condenser tubesheet. Thewaterbox is typically bolted to the condenser with the tubesheet between the waterbox andcondenser flange.


A-1

A SURVEY RESULTS

A survey was sent in August 2000 to the member NMAC and FMAC power plants for detailedinformation on their respective condenser equipment. The intent of the survey was to gatherinformation that could be used by plant personnel that have similar equipment. The results of thesurvey are listed separately for the nuclear and fossil plants and are shown here in Appendix A.

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B-1

B MECHANICAL TUBE CLEANING PROCEDURE

The following is an off-line tube cleaning procedure developed by Conco Systems, Inc. AConfined 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 whenneeded. 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 outletwaterbox.

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 at35 gallons per minute (2.2 liter/second) for each water gun being used. Hook up guns towater source; eliminate all leaks and/or restrictions in lines.

2. Water source can be plant’s water, condensate water, or ash sluice system. Portable BoosterPump 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, withpressed 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 the3/4-inch (1.9 cm) hose (the combination of the swivel and hose reduces wrist fatigue for theshooter).


Mechanical Tube Cleaning Procedure

B-2

5. NEVER USE AIR PRESSURE. NEVER USE QUICK DISCONNECT HOSECONNECTIONS.

Shooting the Condenser

1. Test 5 to 10 cleaners before loading a large amount. Make sure tube cleaning system is inworking 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 manyguns as possible (2000 to 3000 tube cleaners or 25% to 50% of the total number of tubesper waterbox).

3. Insert gun behind cleaner and lock gun into tube by pushing gun straight in and cockingdown and to the side, all in one complete motion. Hold gun firmly in cantilevered positionand 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 thefront of the gun. As the cleaner exits the tube, the gauge should show a pressure drop. If thepressure 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 atone end and have someone at the other end looking through the tubes. If one is blocked, afaint 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.


C-1

C TUBE PLUGGING PROCEDURES

From Table 10-1, Tube Plug Data, the following tables are a listing of the corresponding tubeplug installation procedures. These are the current procedures given by the manufacturer. It isadvisable to check with the manufacturer for any changes or updates to these procedures wheninstalling the tube plugs.

Atlantic Group Brass and Fiber Jacketed Tube

Figure C-1Atlantic Group Tube Installation for Flared and Straight Tube Ends

Table C-1Installation 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 10.2cm) board) or round stock (such as a wooden dowel) that will fit squarely over the entire face ofthe plug. This will ensure that the fiber and brass are driven together. DO NOT DRIVE THEBRASS CARTRIDGE ALONE. The round stock should be only slightly smaller than the tubeinside 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. Ifthe fit is too tight and the plug cannot be installed within 1/4 in. (6 mm) of the tubesheet, contactthe supplier for a smaller size plug. Note that outlet end tubes often extend beyond the tubesheetface; 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 ortubesheet 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 theorder. For the plug to seal properly, it should freely fit 1/8 in. (3 mm) to one-half its length into thetube or tubesheet hole before being driven.


Tube Plugging Procedures

C-2

Bemark Associates, Inc. K-Span Plug

Figure C-2Bemark Associates K-Span Plug

Table C-2Installation 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 thatfits 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 mechanicalstop.

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 mechanicalexpansion stop. Failure to insert the plug fully into the hole or failure to expand the plug to thefullest expansion might cause the plug to leak. If the plug fails to seal the leak, remove theexpander nut and drive the expander out of the back of the expansion body. Remove theexpander body, and then remove the expander. Inspect the hole, clean as required, and repeatthe installation with the largest plug that can be installed.



C-3

Conco Systems, Inc. High Confidence, Expanding, Fiber, Pin, and Pin and Collar TubePlugs

Figure C-3Conco High Confidence Tube Plug

Table C-3Installation 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 oftubes must be properly plugged to prevent stagnant water and/or leaks, which cause furtherproblems.

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 asfar back as possible on the tubesheet and clear of tube rolling transitions. The grips mustengage the tube backed by the tubesheet in a parallel movement to assure maximum grippingaction.

4. Tighten nut on bolt using a screwdriver and box wrench to point where the screwdriver is nolonger required.

5. Torque nut to 50-inch-pounds (5.6 N-m) using a snap-on torque wrench of a 30–200 inch-pounds (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 therecommended torque or 50-inch-pounds (5.6 N-m). Torque further as needed for site-specificapplications. Torque ranges of 50 to 100 inch-pounds (5.6 –11 N-m) should satisfy allapplications.

8. Installation is now complete. For installations without lock nuts, Conco suggests the use ofLoctite adhesive to hold the nut in place.



C-4

Figure C-4Conco EX-3 Expanding Tube Plug

Table C-4Installation 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-5Conco EX-F Expanding Tube Plug



C-5

Table C-5Installation Procedures for the Conco EX-F Expanding Tube Plug


2. Insert plug into tube beyond flush of tubesheet.

3. Hand-tighten finger tight, then using deep well socket wrench, turn nut 2-3 completerevolutions.

4. The end of the bolt is slotted. Use a screwdriver to hold the bolt in place while tightening thenut with a 7/16 in. (11 mm) box wrench. Tighten to desired torque.

Figure C-6Conco FP Fiber Tube Plug

Table C-6Installation Procedures for the Conco Fiber Tube Plug


2. Using hammer, lightly pound plug into tube.

Figure C-7Conco Pin Plug



C-6

Table C-7Installation Procedures for the Conco Pin Plug


2. Using hammer, lightly pound plug into tube or tubesheet.

3. Can be welded into position if necessary.

Figure C-8Conco Pin and Collar Tube Plug

Table C-8Installation 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-7

Expansion Seal Technologies VibraProof, Perma, and Expandable Thimble Plug

Figure C-9Expansion Seal Technologies VibraProof Condenser Plug



C-8

Table C-9Installation 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 torquewrench. 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 tubeholes; 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, shouldbe established and followed.

Figure C-10Expansion Seal Technologies Condenser Perma Plug



C-9

Table C-10Installation 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 tubeend/tube hole by brushing with EST’s Tube Cleaning Brushes. A properly sized brush will be a tightinterference 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 coppernickel 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 andcorrosion. It reduces tube ovality and sizes the tube; and it provides an ideal sealing surface for thePerma Plug.) Stop brushing after each interval and visually inspect the tube. If brushing hasaccomplished its objectives, continue to the next step. If not, brush for another interval and re-inspect. If the brush feels loose in the tube it might be necessary to move up to the next larger brushsize and continue brushing. Brushing can be facilitated by periodically dipping the Tube CleaningBrush in Brush Lube. Re-gage the tube end with the Go / No-Go gage to confirm the correct plugsize.

3. Insert the Pull Rod Assembly into the Ram and recess the plug within the tube end or tubesheethole so that the installed plug will be flush with or slightly recessed from the tubesheet face. Alwaysinstall the plug within the region of the tubesheet.

4. Operate the ram until the integral breakaway pops and the plug is set. Remove the remainingbreakaway piece from the end of the conical pin.

Note: field experience has shown that total installation time for Perma Plugs from initial preparationthrough plug installation is generally 2-4 minutes per tube end.

Figure C-11Expansion Seal Technologies Expandable Thimble Plug



C-10

Table C-11Installation 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 endfrom the tubesheet hole.

2. Brush the tubesheet hole using a properly sized tube cleaning brush. Brushing will removeany 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 tubesheethole. 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 thetubesheet face.

6. (Optional) Carefully drive a fiber hammer-in taper plug to the open end of the installed thimbleto identify that the tube end has been plugged.

Heat Exchanger Products Inc. (HEPCO) Brass Condenser Tube Plug

Figure C-12HEPCO Brass Condenser Tube Plug

Table C-12Installation 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. (3.7N-m) and torque down hex head nut.



C-11

Torq N’ Seal™ Condenser Plug and High Pressure Tube Plug

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

Table C-13Installation 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 expansionscrew is used to reduce the plug diameter.

2. Remove the end cap by turning to the right. Insert a slotted screwdriver into the expansionscrew and turn to the left. That will reduce the diameter until the plug fits into the tube insidediameter.

3. Be sure to wipe the tube inside diameter with a clean cloth so that it is dry before installation ofthe plug to ensure a good friction fit.

4. Insert the Torq'N Seal¥ Condenser Plug into the tube with the flange pressing against thetubesheet. Tighten the expansion screw to the right until the plug is seated as tight as possiblewithout stripping the slotted head. Replace the protection end cap onto the expansion screw byturning to the left. See Figure C-13.

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



C-12

Table C-14Installation 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 tubemicrometer 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 ofthe tube or remove the tube completely.

3. After the correct size plug is chosen, a ratcheting torque wrench should be used to install theplug. Insert the plug into the tubesheet area of the heat exchanger. Use of Screw Grab will holdthe 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 theright until you feel the eccentric cam lock in place. If the cam does not lock, then the plug is toosmall for that particular application. After the cam locks, the applied torque will feel as if there isan even resistance (approximately 150 in. lb.) (17 N-m) as the plug body expands. When thetorque necessary to tighten the plug increases, use an accurately calibrated torque wrench toachieve the final torque value as follows:

Plug Material Plug Size - in. (mm) Torque - In. lbs.(N-m)

Drive Size

0.430 – 0.560(11 – 14)

400 (45.2) Torx T45

0.570 – 0.710(14.5 – 18.0)

450 (50.8) Torx T50

Carbon Steel

0.730 – 0.980(18.5 – 25)

500 (56.5) 3/8 in. Hex(9.5 mm)

0.430 – 0.560(11 – 14)

250 (28.2) Torx T45

0.570 – 0.710(14.5 – 18.0)

300 (33.9) Torx T50

Brass

0.730 – 0.980(18.5 – 25)

350 (39.5) 3/8 in. Hex(9.5 mm)

0.430 – 0.560(11 – 14)

250 (28.2) 1/4 in. Hex(6 mm)

0.570 – 0.710(14.5 – 18.0)

300 (33.9) 5/16 in. Hex(8 mm)

Cupra Nickel

0.730 – 0.980(18.5 – 25)

350 (39.5) 3/8 in. Hex(9.5 mm)

0.430 – 0.560(11 – 14)

500 (56.5) 1/4 in. Hex(6 mm)

0.570 – 0.710(14.5 – 18.0)

550 (62.1) 5/16 in. Hex(8 mm)

Stainless Steel

0.730 – 0.980(18.5 – 25)

600 (67.8) 3/8 in. Hex(9.5 mm)


D-1

D POP-OUT SUMMARY

The following list provides the location of key Pop-Out information in this report.


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]. Bothcompare the current value of the effective heat transfer coefficient (Ueff),computed from present steam and water temperatures and cooling water flowrate, 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 valueand the HEI reference value is an overall tube bundle heat transfer coefficient.The value of the effective cleanliness factor (HEI method) is greater than thecorresponding performance factor (ASME method) on the same condenser. Ithas also been observed that the design value of the ASME performance factorand the HEI cleanliness factor varies with load.

5.4.2 5-20 To be effective in controlling biofilm formation all biocides require adequatedosage, 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 allapplications. It also lists danger signs, environmental hazards, treatmentmethods, storage and disposal instructions, and how to apply initial andsubsequent dosages.

5.4.3 5-23 The Environmental Protection Agency (EPA) and the states mandate three typesof regulations governing the quality of discharges. They are technology-basedregulations, historically based effluent water quality standards, and receivingwater quality-based standards.

5.4.3.1 5-25 In general, the technology-based regulations are species or compound-specificnumerical limits, either concentration or mass per unit time. These limitations arebased on the performance of the best available technology on the particularcategory of effluent for a particular industry. These limitations are typically theleast restrictive limits that can be imposed.

5.4.4 5-26 Oxidizing biocides are usually the primary biocontrol agents for once-throughand recirculating condenser cooling water systems. Non-oxidizing biocidesseldom are used in once-through condenser cooling water systems except forspecial applications such as macrofouling control.


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5.4.4.1 5-27 Chlorine gas is very toxic and extremely irritating. It is a green vapor that isdenser than air. Small leaks can be detected with a 10% solution of ammoniahydroxide. The chlorine and ammonia vapors form a white vapor of ammoniumchloride.

5.4.4.1 5-28 Appropriate safety equipment such as chlorine gas masks should be available incase a leak occurs in feedlines or at cylinder connections. Consult the MaterialSafety Data Sheet and product label for specific safety handling and spillprecautions.

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 feedsodium hypochlorite. Consult the Material Safety Data Sheet and product labelfor 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 feedchlorine. A dust mask can also be used. Consult the Material Safety Data Sheetand 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 feedingbromine compounds. Consult the Material Safety Data Sheet and product labelfor specific safety handling and spill precautions.

5.4.4.3 5-36 For non-oxidizing biocides, appropriate safety equipment such as facemask, eyegoggles, rubber gloves, and apron should be worn when handling any equipmentused to store or feed the chemicals. Some of the non-oxidizing biocides areextremely irritating. They can penetrate clothing, shoes, or leather and arerapidly absorbed through the skin. Some emit toxic irritating vapors. Great careshould be taken in handling all non-oxidizing biocides. Consult the MaterialSafety Data Sheet and product label for specific safety handling and spillprecautions.

5.4.4.3 5-36 Biocides are regulated by the EPA. Each biocide must be registered for aspecific use such as microbiological control. In addition, it must be registered forthe specific cooling water systems in which it can be used. The container labelmust specify a variety of information, including at a minimum, the percent ofeach 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 systemoperation. The manufacturers normally recommend replacing a complete chargeof balls approximately once a month because of ball wear. Historical operatingdata show that ball usage is often much higher. New designs might be animprovement in ball life.

6.2.5 6-21 When high-pressure water lancing equipment must be used, it presents apotential safety hazard to operating personnel because of pressures as high as8000-10,000 psi (55-69 megapascals). Often this equipment is used by acontractor who specializes in high-pressure equipment. Propelling the cleaningdevices through the tubes with high-pressure air or air/water also presents asafety 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 theunit, continue around the turbines, include any other components on the deckapplicable to the test, and then proceed in a similar manner with the next deck


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D-3


down. Regardless of the type of gas used for testing, the test should beperformed 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 tounknown 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 thepresence of condenser in-leakage.

7.4.2 7-29 Water chemistry guidelines for PWR once-through and recirculating steamgenerators can be found in EPRI TR-102134-R5, PWR Secondary WaterChemistry 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 pluggingcan be considered good maintenance practice. In many cases, the exactmechanism that caused the tube to fail is uncertain. Selecting surrounding tubesto be plugged is insurance against additional leaks developing before the nextoutage. Those tubes with insurance plugs can then be subjected to eddy currenttesting during the next outage so that as many tubes as possible can be returnedto service.

7.5 7-31 Once the leaking bundle has been identified, a number of methods are availableto determine exactly which tubes or joints are leaking. All of the methodscommonly used involve testing areas of the tubesheet sequentially until the areaof the leak(s) is evident. Testing then progresses to smaller areas until the exactleak location is found. The most commonly utilized leak location methods aretracer 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 sulfurhexafluoride (SF6) to detect and locate condenser tube leaks while thecondenser is in full operation. The system is called the Condenser On-Line LeakDetection System (COLDS) and a description of it is found in EPRI documentAP101840-V3P2, published in December 1995. It can locate leaks with flowrates as low as 1 gallon (4 liters) of water per day and small leaks that cannot belocated with off-line techniques.

8.1.1 8-2 INPO determined that the following are causes of the personnel injuries fromHydrolaser 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 corrosionduring outages. Exposure of condenser parts to stagnant water during lay-upcan lead to accelerated, localized corrosion.

9.4.4.1 9-18 Where the bidding process might result in a different contractor being employedfor each inspection, the necessity for a common procedure ensures that eddycurrent data from one inspection can be compared with confidence to the datafrom inspections conducted in earlier years. Without such formal procedures andowner supervision, reliable data trending is virtually impossible.


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D-4


9.4.4.6 9-19 The term figures of merit as used in the analysis of eddy current tests is thegeneric name applied to various criteria used to compare test results. Figures ofmerit have different criteria in the case of a condenser compared with those for aheat exchanger. With heat exchangers, considerations of meeting the PressureVessel Code override questions of mere wall penetration. In any given plant,there should be some agreement on how corrosion figures of merit will bedefined when evaluating eddy current test results.

10.5 10-22 Tubes in service have defects. These defects or indentations can result frominstallation or in-service conditions. The liner might not be able to overcome alltube inside diameter defects and, thus, will not be expanded to meet the tubeinside diameter by hydro-expansion. The defects create air pockets that cansignificantly retard heat transfer. Because of the uncertainty of the applicationresults, it is recommended that heat transfer studies be conducted on severalsamples of the tubes to be lined. In this way, the effect on heat transfer can beestablished 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 2–4mils (51–102 µm). However, the actual coating thickness selected has to bebalanced between solving a particular problem and retaining sufficient tube heattransfer capability.

11.5.1.4 11-25 Recent improvements in technology have resulted in tooling that can pull anentire 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 spacerequired for tube removal.

11.5.1.8 11-28 Sufficient labor should be planned for tube insertion. Good practice is to provideone worker for each 10 feet (3 meters) of tube to be inserted.


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D-5

Key O&M Cost 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 outletmust be at the same end of the condenser. In plants with cooling towers, a twopass 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 low-pressure turbine without a significant decrease in the temperature of thecondensate leaving the hotwell. The lower condenser backpressure meansincreased turbine efficiency.

4 4-1 Condenser performance significantly affects the heat rate and generation capacityof a power plant. A 1 in. Hg (2.5 cm Hg) increase in turbine backpressure canresult 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 isrelatively low in cost. Unfortunately, chlorine gas is highly toxic. Sodiumhypochlorite, 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 oxidizingbiocides, but site-specific conditions could change this. Generally, non-oxidizingbiocides are applied once per week or several times per month, as compared toseveral times daily for the oxidants.

10.1.2 10-3 In situations where previously installed plugs are missing, leaking, or have causedcollateral damage to the tube and tubesheet, the actual plug cost should not be amajor factor. The expense associated with controlling persistent water in-leakageas a result of tube and plug leaks can be many times the cost of even the mostexpensive plug.


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D-6

Key Technical 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 designcode applicable to condensers in the utility industry is the Heat ExchangeInstitute (HEI) standards.

2.5.5 2-15 In the air-removal section of the tube bundle, the tubes are exposed to anoxygenated, ammonia-rich environment. This environment promotes condensatecorrosion (grooving) in copper-alloy tube materials. For this reason, the tubematerials in this section are made from a more corrosion-resistant alloy such asstainless steel.

3.1 3-2 Backpressures lower than design tend to improve heat rate. Therefore, lowerbackpressures are desirable. However, the backpressure should not be so lowthat it is the cause of unnecessary condensate subcooling (see the discussion inSection 4.1.1).

3.3.2 3-7 A gradual decrease in vacuum by the steam jet air ejectors could be caused by acorroded or eroded nozzle, condensate trap mis-operation, clogged loop sealdrain pipe, leaking cooler tubes, and wet steam.

4.7 4-10 The following parameters should be measured when monitoring condenserperformance: inlet and outlet tube side pressure, inlet and outlet cooling watertemperature, impressed cathodic protection settings, condenser cleanlinessfactor, sample fluids for contamination, turbine backpressure, and air in-leakagelevels.

5 5-1 There are two main types of biofouling: macrofouling and microfouling.Macrofouling is defined as the blockage of condenser tubes by organic orinorganic debris such as sticks, leaves, fish, mussels, and so on. Microfouling isthe accumulation of deposits (inorganic scales or organic growths) on the insideof the tubes.

5.2 5-4 A variety of macrofouling control technologies are used in power plants. Thesetechnologies can be categorized as: mechanical control, flow reversal, thermalbackwash, hydraulic control, materials control, chlorination and alternatebiofouling control methods, and manual cleaning.

5.2.3 5-11 Thermal backwash is an antifouling technique that requires the cooling watertemperature to be raised above the thermal tolerance level of the foulingorganism, for example, zebra mussels.

5.2.4 5-12 The use of high circulating water velocity to prevent the attachment andsubsequent growth of fouling mechanisms is termed hydraulic control. Thevelocity needed to prevent settlement of the fouling organisms is between 2 and4 ft/sec (37 and 73 meter/min) on smooth surfaces and 4 to 6 ft/sec (73 to 110meter/min) on rough surfaces.

5.2.5 5-13 Copper-nickel alloys form an adherent cuprous oxide corrosion film. The copperion content in the film, when released into the cooling water, is toxic to marinebiofouling 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


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D-7


including surface conditions, water quality, fluid velocity, water temperature, andtube alloy.

5.3.2 5-19 Chemical additives used for biological control or corrosion inhibition can alsoresult in microfouling. For example, water that contains manganese will reactwith chlorine to form manganese dioxide particles and substantially increasefouling risk. Copper alloys and 300 series stainless steels are likely to suffersignificant corrosion under these circumstances.

5.4 5-19 Several factors must be considered when using chemicals to control microfoulingof main steam condenser cooling water systems. These factors includecondenser cooling system design and operation, biocontrol agents,environmental regulations, chemical application methods, and safety andexposure.

6 6-1 Some performance parameters that indicate condenser cleaning is needed areincreased condenser backpressure, decreasing cleanliness factor, decrease ininlet and outlet cooling water temperature difference, heat rate increase, andmegawatt output decrease.

6 6-2 The on-line cleaning techniques include the sponge ball system, brush and cagesystem, abrasive cleaning, and self-aligning rockets. These systems can requirea large capital investment. A continuous cleaning system offers the advantage ofkeeping the tubes clean without any fouling buildup. Some additionalmaintenance and operations attention is required. The constant scraping of thetube inside walls can cause tube thinning.

6 6-3 The off-line cleaning techniques include the use of brushes, scrapers, andhydroblasting. The equipment costs for these systems are relatively inexpensive.The unit must be derated or off-line in order to clean the tubes. Tube cleaningcan be scheduled during refueling/boiler outages or during a scheduled loadreduction. The cleaning process requires an operator and the air and waterpressures 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 onewaterbox at a time or to the entire condenser. The off-line techniques apply tothe entire condenser. Chemical cleaning of the condenser typically regains lostmegawatts.

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. Aleakage on the order of 0.1 gallons per minute (gpm) (23 liters/hr) might beunacceptable and can cause significant corrosion.

8.2.3 8-13 Dezincification of Muntz metal is the most commonly reported dealloyingproblem 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 caseswhere galvanic-induced corrosion is significant, such as a Muntz metaltubesheet fitted with titanium tubes, dezincification has occurred at penetrationrates 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 galvaniccorrosion are the potential differences between the metals, the environmentalaspects of the electrolyte, the polarization behavior of the respective metals, andthe relative areas of the coupled metal. The environmental factors having thegreatest effect on the galvanic corrosion rate are cooling water conductivity and


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D-8

Section Page Key Pointtemperature.

8.2.8 8-18 Random pitting along the length of a condenser tube is the most commonlyencountered condenser corrosion problem. Pitting is manifested most frequentlyin 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 dropletstraveling at a high speed and impacting on the surface of the tubes. The severityof impingement attack is a function of the kinetic energy of the fluid, the impactvelocity, the mass flow per unit area, the hardness of the tube material, and theexposure time.

8.2.11 8-20 Flow-induced vibration damage occurs in condensers because the spacingbetween supports is too large or because the baffling at high-energy inletconnections does not provide adequate dispersion of the flow jet at theconnection.

9.3.1 9-4 Cleaning by mechanical and/or chemical techniques is the only preventive taskthat prevents corrosion or slows its progression, maintains tube reliability, andextends the life of the tubes.

9.4.4 9-15 ET is a non-destructive test technique that causes electrical currents to beinduced in the material being tested. The associated magnetic flux distributionwithin the material is then observed. Because the results from eddy currenttesting can be affected by a number of factors, successful eddy current testingrequires a high level of operator training and awareness.

9.4.4 9-16 Eddy current instruments and recording instruments have a limited frequencyresponse, 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 poorexamination. Most testing should be performed at probe speeds of 60 to 120 feetper 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 bringingthe tubes to a clean state, the possible effects on the electromagnetic fluxdistribution 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 rangeof 50-90 percent wall loss. Consequently, if the eddy current sizing error of 10percent 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, haveno negative effect on heat transfer, and reduce the tube opening by a fraction ofthat associated with plastic tube inserts.

10.2 10-18 Corrosion-resistant insert materials typically specified are: AL-6X, AL-6XN, 70-30, 85-15 or 90-10 Cu-Ni and 304 or 316 Stainless Steel. AL-6X is the mostwidely used insert material.

10.4 10-20 An alternative approach to tube inserts for tube end erosion/corrosion problemsis to apply a tube end epoxy coating that can halt the erosion process. Thecoatings 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 tubeend, 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 coatedis not significant because the coating is compatible with all tube materials.

10.8 10-25 Manufacturers recommend that epoxy coatings not be subjected to hightemperatures (> 170°F (76.6°C)) or allowed to freeze. If tubes mounted in


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D-9


tubesheets that have had the cladding applied, subsequently leak, they shouldnot be plugged with tapered brass or fiber plugs. Expandable plugs are preferredbecause they do not put pressure on the coating. Plugs should never behammered into tubes in tubesheets after they have been coated.

10.10 10-29 The material selection for coating waterboxes depends on whether thewaterboxes 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 plantuse epoxy coatings for performance, longevity, and personnel safetyconsiderations.

11 11-1 The current industry experience has been to replace copper-bearing alloys withhigh alloy, pit-resistant steels and titanium. These materials are significantlylighter in weight and higher in yield strength, but they have lower thermalconductivities than the copper-bearing alloys.

11 11-2 Another consequence of retubing with one of the newer materials is the likelyneed for additional tube support plates or tube staking to reduce the tendency ofthe tubes to vibrate.

11.3.4 11-19 The primary advantage of an expanded and welded joint is that it can providegreater axial strength and better leak integrity than an expanded joint for titaniumand 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 inthe number of tubes. This increase in tube side flow area generally results inreduced condenser circulating water pressure drop and an increase in circulatingwater discharge from the existing circulating water pumps. The resulting totalcirculating water flow to the rebundled condenser is higher. Generation might beincreased with a more efficient design.


Technical Report

LI

CE

NS E D

M A T E

RI

AL

Equipment

Reliability

Plant

Maintenance

SupportReduced

Cost

WARNING:Please read the License Agreementon the back cover before removingthe Wrapping Material.

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This shrink-wrap license agreement is subordinate to the terms of the Master Utility License Agreement between most U.S.EPRI mem-ber utilities and EPRI.Any EPRI member utility that does not have a Master Utility License Agreement may get one on request.

2. COPYRIGHTThis package, including the information contained in it, is either licensed to EPRI or owned by EPRI and is protected by United Statesand international copyright laws.You may not, without the prior written permission of EPRI, reproduce, translate or modify this pack-age, in any form, in whole or in part, or prepare any derivative work based on this package.

3. RESTRICTIONS You may not rent, lease, license, disclose or give this package to any person or organization, or use the information contained in thispackage, for the benefit of any third party or for any purpose other than as specified above unless such use is with the prior writtenpermission of EPRI.You agree to take all reasonable steps to prevent unauthorized disclosure or use of this package. Except as speci-fied above, this agreement does not grant you any right to patents, copyrights, trade secrets, trade names, trademarks or any otherintellectual property, rights or licenses in respect of this package.

4.TERM AND TERMINATION This license and this agreement are effective until terminated.You may terminate them at any time by destroying this package.EPRI hasthe right to terminate the license and this agreement immediately if you fail to comply with any term or condition of this agreement.Upon any termination you may destroy this package, but all obligations of nondisclosure will remain in effect.

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(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USEOF ANY INFORMATION,APPARATUS, METHOD, PROCESS OR SIMILAR ITEM DISCLOSED IN THIS PACKAGE, INCLUDINGMERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON ORINTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY’S INTELLECTUAL PROPERTY, OR (III) THAT THISPACKAGE IS SUITABLE TO ANY PARTICULAR USER’S CIRCUMSTANCE; OR

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